Provident Energy Trust

Provident Energy Trust

March 14, 2005 09:02 ET

Provident Energy Announces 2004 Year-end and Fourth Quarter Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: PROVIDENT ENERGY TRUST

TSX SYMBOL: PVE.UN
AMEX SYMBOL: PVX

MARCH 14, 2005 - 09:02 ET

Provident Energy Announces 2004 Year-end and Fourth
Quarter Results

CALGARY, ALBERTA--(CCNMatthews - March 14, 2005) - Provident Energy
Trust (Provident) (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.

2004 Highlights

- Provident was the first Canadian energy trust to acquire significant
oil and gas assets in the United States, purchasing Los Angeles-based
BreitBurn Energy. The acquisition created Provident's third business
unit and strengthened the trust by providing a long-term source of cash
flow.

- Provident's acquisitions, internal development activities and overall
strong commodity prices increased the trust's consolidated proved plus
probable oil and gas reserves from 54,894 Mboe (0.66/unit) to 130,800
Mboe (0.92/unit).

- Provident's proved plus probable reserve life index (RLI) at December
31, 2004 was 9.3 years, a 40 percent increase over 2003. The increase
reflects the acquisition of long-life reserves in the U.S., acquisition
and internal development activities in Canada, and overall strong
commodity prices. Incorporating the long-life midstream assets,
Provident's economic life is greater than 13 years.

- Provident's finding, development and acquisition (FD&A) costs in 2004
including future capital and revisions based on NI 51-101 reporting
guidelines were $14.07/boe for total proved reserves and $11.58/boe for
proved plus probable reserves. Provident's three year average total
proved plus probable FD&A cost were $10.68/boe, including future
development capital and NI-51-101 revisions.

- Provident's consolidated oil and gas exit production was 36,700 boed,
compared to 26,190 boed in 2003. 2004 consolidated exit production was
weighted 40 percent to natural gas, 42 percent to light/medium oil and
NGLs, and 18 percent to heavy oil.

- Provident's Midstream Services and Marketing group exceeded earnings
before interest, taxes and depreciation (EBITDA) expectations,
generating EBITDA of $50.1 million in 2004, well above market
expectations of $38 to $42 million.

- Provident maintained its monthly cash distribution at $0.12/unit
throughout 2004, distributing a total of $164.6 million ($1.44/unit),
representing a payout ratio of 89 percent of cash flow from operations.

Provident Energy Trust (Provident) (TSX - PVE.UN; AMEX-PVX) today
reported 2004 cash flow from operations of $185.2 million ($1.59 unit),
compared to $128.4 million ($1.88/unit) in 2003. Distributions paid in
2004 totaled $164.6 million ($1.44/unit), compared to $129.6 million
($2.06/unit) in 2003. For the year, Provident's payout ratio of cash
flow from operations was 89 percent, compared to 101 percent in 2003.
Provident has early adopted and retroactively applied the classification
of convertible debentures as debt and netted the interest expense from
cash flow and income. Consequently, adjusted cash flow is no longer
relevant.

"Provident Energy ended 2004 a very different trust from 2003. In 2004,
Provident completed the corporate acquisitions of Olympia Energy and
Viracocha Energy in Alberta, and Los-Angeles based BreitBurn Energy.
BreitBurn subsequently executed the acquisition of the Orcutt Field in
California's Santa Maria Basin, providing Provident an even stronger
U.S. base," said Provident Chief Executive Officer Tom Buchanan "The
acquisitions of Olympia and Viracocha were accretive to Provident's cash
flow and production on a per unit basis, while the acquisitions of
BreitBurn and Orcutt were highly accretive to reserves and net asset
value on a per unit basis and added high-quality, long-life crude oil
and gas production assets at attractive valuation metrics."

"In the last 18 months, Provident has executed its balanced portfolio
strategy. We have established three distinct business units - Midstream
Services, U.S. Oil and Gas Production and Canada Oil and Gas Production
- and in so doing we have improved the stability of cash flows. We have
also positioned Provident for growth outside of the intensely
competitive Western Canada Sedimentary Basin and enhanced the
sustainability of the trust."

Fourth quarter 2004 cash flow from operations was $58.4 million
($0.41/unit), compared to $30.3 million ($0.37/unit) in fourth quarter
2003. Distributions declared in fourth quarter 2004 totaled $52.1
million ($0.36/unit), compared to $32.0 million ($0.39/unit) in 2003.
For the three months ended December 31, 2004, Provident's payout ratio
of cash flow from operations was 89 percent, compared to 105 percent for
the same period in 2003.

Business Unit Results

Provident has diversified investments across the energy value chain in
Canada and the United States. The business is managed within three key
business units - Midstream Services and Marketing (Midstream), U.S. Oil
and Gas Production (USOGP) and Canada Oil and Gas Production (COGP).

Midstream Services and Marketing

Provident's Midstream business unit generates cash flow by providing
fee-based services, including extraction, transportation, storage,
distribution and marketing of NGLs to petroleum producers and refiners,
petrochemical companies and marketing firms.

For 2004, Provident's Midstream business unit generated EBITDA of $50.1
million and cash flow from operations of $42.6 million. For the fourth
quarter 2004, Midstream earned EBITDA of $18.0 million and cash flow of
$16.6 million. Annual throughput at the Redwater fractionation facility
averaged 55,120 bpd. For the three months ended December 31, 2004,
throughput was 56,452 bpd, compared to 63,616 bpd for the fourth quarter
of 2003. In 2004, outages on a liquids gathering system and a third
party delivery system contributed to a reduction in throughput at the
Redwater facility. The reduced throughput in the fourth quarter was also
a result of a seven-day shutdown in October which was required for the
installation of a back-up, deethanizer reboiler.

"In 2004, the Midstream Services and Marketing group exceeded our EBITDA
expectations, despite third-party operational challenges that restricted
throughput at the facility last May and June," said Provident President
Randy Findlay. "The addition of the Midstream Services business to
Provident has enhanced the stability and sustainability of the trust.
The Midstream Services business differentiates the trust and ideally
positions Provident to participate in the future growth of the NGL
processing business driven by drilling in Northern Alberta and British
Columbia, and the potential for future transportation of liquids rich
natural gas from the Mackenzie Delta and Alaska."

U.S. Oil and Natural Gas Production

Provident's USOGP business unit produces cash flow from the production
and sale of natural gas and crude oil from basins in Southern California
and Wyoming. BreitBurn Energy LP operates 100 percent of the production.
Provident's interest in BreitBurn is approximately 94 percent.

On June 16, 2004, Provident completed the acquisition of BreitBurn
Energy LLC, a private exploitation and production company based in Los
Angeles, California. The acquisition added approximately 3,634 boed of
incremental production in the second half of 2004 and 39.9 million boe
of proved plus probable reserves to Provident. Subsequent to the
original BreitBurn acquisition, additional interests were purchased in
the Sawtelle and East Beverly Hills fields adding an incremental 2.5
million boe of proved plus probable reserves to BreitBurn. The reserve
values are based on year-end engineering and pricing forecasts, and
backed up to the effective dates of the acquisitions by actual
production received.

Aggregate consideration for the shares of BreitBurn was $157.4 million
in cash and the assumption of $33.6 million of working capital
deficiency and financial obligations of BreitBurn for a total purchase
price of $191 million. Under terms of the transaction, Provident
reorganized BreitBurn into a Limited Partnership (LP). BreitBurn
co-founders and co-chief executive officers, Randall Breitenbach and
Halbert Washburn, acquired an original eight percent interest in the LP
for $13.7 million and continue to lead BreitBurn's business in the U.S.
as co-CEOs.

On October 4, 2004, BreitBurn closed the $58.5 million property
acquisition of the Orcutt Field in the Santa Maria Basin, adding
approximately 1,425 boed of incremental production in the fourth quarter
of 2004 and 12.2 million boe of proved plus probable reserves.

"Our most defining actions in 2004 were the acquisition of BreitBurn
Energy and the addition to the Provident team of an experienced, highly
technical U.S.-based management team committed to creating long-term
value for Provident unitholders," said Mr. Findlay.

"BreitBurn is an exciting new addition to Provident's portfolio and
represents a significant step in our ongoing evolution. With reserve
life indices over 20 years, natural decline rates of approximately six
percent and significant development opportunities these newly acquired
mature U.S. oil and gas fields provide long-term sources of cash flow.
The U.S. oil and gas business also adds significant depth to our already
diversified portfolio, well positions Provident for future U.S.
acquisitions and sets Provident apart from other energy trusts."

From June 16 to December 31, 2004, USOGP generated $21.5 million of cash
flow from operations. In the fourth quarter of 2004, USOGP generated
$11.5 million of cash flow from operations. There are no comparable
periods, as Provident began reporting USOGP segment results in the third
quarter 2004.

For the latter six and half months of 2004, USOGP production averaged
4,237 boed and was weighted 92 percent to light/medium oil and eight
percent to natural gas. Fourth quarter 2004 USOGP production averaged
5,010 boed and was weighted the same as the year average. Production
includes incremental production from the Orcutt Field, which was
acquired on October 4. At December 31, 2004, USOGP's production was
approximately 5,200 boed.

USOGP operating costs averaged $15.62/boe for the latter six and half
months of 2004 and were $15.16/boe during the fourth quarter. Operating
costs are expected to be between $13.00 and $13.50/boe for 2005. Field
operating netbacks on USOGP production for the second half of 2004 were
$32.54/boe and $33.49/boe for the fourth quarter 2004. USOGP capital
expenditures for the second half of 2004 totaled $20.8 million. For the
fourth quarter, capital expenditures were $4.6 million. For 2005,
Provident estimates its U.S. capital program will be approximately $41
million, with drilling and related expenditures in the West Pico, Santa
Fe Springs and the recently acquired Nautilus properties accounting for
the balance of the capital expenditures.

Canada Oil and Gas Production

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

On June 1, 2004, Provident closed the concurrent acquisitions of all
outstanding shares of Olympia Energy and Viracocha Energy, adding
approximately 9,000 boed of incremental production in the second half of
2004. Aggregate consideration for Olympia and Viracocha was
approximately $227.8 million and $210.5 million, respectively, paid
through the issuance of Provident units and the assumption of debt and
working capital.

"Through a combination of drilling success and new acquisitions, Canada
OGP delivered against our objectives and met expectations in 2004," said
Mr. Findlay. "We are particularly pleased with the results of our
development activities in Lloydminster and Southern Saskatchewan, which
led to the replacement of approximately 40 percent of our Canadian
production on a proved plus probable basis. While we will continue to
seek quality acquisitions in Canada, internal development and production
optimization in and around our existing assets will be a primary focus
for our Canadian operations. To support our internal development and
production optimization focus, as well as build on drilling programs
initiated in 2004, Provident's COGP capital budget has been approved at
approximately $69 million in 2005."

From a financial perspective, in 2004 COGP generated $121.1 million of
cash flow from operations, compared to $119.6 million for 2003. In the
fourth quarter 2004, COGP earned $30.3 million cash flow from
operations, compared to $21.6 million for the same period in 2003. The
year over year COGP cash flow from operations is relatively flat
reflecting a five percent increase in production volumes partially
offset by higher operating costs.

Operationally, 2004 COGP production averaged 28,781 boed compared to
27,314 boed in 2003. For the year, COGP production was weighted 44
percent to natural gas, 33 percent to light/medium oil and NGLs and 23
percent to heavy oil. For the fourth quarter, COGP production was 31,863
boed compared to 26,193 boed in fourth quarter 2003. Fourth quarter 2004
production was weighted 45 percent natural gas, 34 percent medium/light
oil and NGLs, and 21 percent heavy oil. At December 31, 2004, COGP's
production was approximately 31,500 boed, compared to 26,190 boed a year
ago at this time.

For 2004, COGP operating costs averaged $8.58/boe, compared to $7.66/boe
in 2003. Fourth quarter 2004 operating costs were $9.02/boe, compared to
$8.96/boe in the third quarter of 2004 and $8.99/boe in the fourth
quarter of 2003. The year over year increase in operating costs was due
to greater processing fees and down hole costs, and higher fuel and
power costs. For 2005, Provident estimates COGP operating costs will
range between $9.00 and $9.25/boed. Field operating netbacks on COGP
production for 2004 were $21.33/boe and $20.49/boe for the fourth
quarter 2004.

In 2004, Provident's internal capital program added approximately 4,300
boed of initial production at a cost of approximately $14,000 per
flowing boe. Provident's total capital program in 2004 was $60.3
million. Comparatively, in 2003 Provident spent capital of $31.6 million
and added 3,200 boed of initial production. In the fourth quarter 2004,
$24 million was spent and 1,400 boed of initial production was added,
compared to $7.5 million and 300 boed of initial production during the
year ago period.

Consolidated U.S. and Canada Oil and Gas Reserves

Provident had a successful year with respect to reserves additions which
directly enhance the sustainability of the trust. The trust's reserves
more than doubled after production with proved producing reserves
growing from 35,466 Mboe to 73,715 Mboe, total proved growing from
41,868 Mboe to 99,627 Mboe, and proved plus probable growing from 54,894
Mboe to 130,800 Mboe. Acquisitions accounted for most of the growth in
reserves volumes however it is noteworthy that internal development
activities in Western Canada were successful in replacing approximately
36 percent of total trust production. As a result, in 2004 Provident's
finding, development and acquisition (FD&A) costs including future
capital and revisions based on NI-51-101 reporting guidelines were
$14.07/boe for total proved reserves and $11.58 /boe for proved plus
probable reserves. Provident's three year average total proved plus
probable FD&A cost were $10.68/boe, including future development capital
and NI-51-101 revisions.

Reserve life indices (RLI) increased largely due to the acquisition of
low decline, long life reserves in the U.S. The 2004 year end RLI's were
determined by applying the average 2005 production rate from the
McDaniel and Associates (McDaniel), Netherland, Sewell and Associates,
Inc. (NSA), and Cawley, Gillespie and Associates, Inc. (CGA) evaluations
to the remaining volumes as of January 1, 2005. Compared to the previous
year, at year end 2004 Provident's proved producing RLI increased from
4.3 to 6.2 years, total proved RLI increased from 5.0 to 7.5 years and
proved plus probable RLI increased from 6.6 to 9.3 years.

It is important to note that the long-term, stable cash flow from the
midstream services business significantly extends Provident's economic
life. For this reason economic life as a measure of Provident's future
cash flows is more representative than the typically referenced reserve
life index. Based on a 25 year life for the Redwater facilities which
Provident acquired in 2003, Provident's economic life index increased
year over year from 11.2 to 13.4 years.

In order to provide clarity in Provident's reserve reporting reserves
are illustrated by country and on a consolidated basis within the MD&A.
The Canadian and U.S. evaluation reports used the McDaniel price
forecast at January 1, 2005 and are prepared in accordance with
disclosure standards as mandated by the Canadian Securities
Administrators' National Instrument 51-101 (NI 51-101) Standards of
Disclosure for Oil and Gas Activities. Provident's Canadian oil and
natural gas reserves as of December 31, 2004 were evaluated or reviewed
by McDaniel. Provident's U.S. oil and natural gas reserves as of
December 31, 2004 were evaluated by NSA and CGA.

A conference call with senior management to review the quarter results
is scheduled for 9:00 a.m. MT (11:00 a.m. ET) on Monday, March 14.
Analysts, investors and media may access the conference call by dialing
(416) 695-5259 in the Toronto area and 1-888-789-0089 for all other
areas of Canada and the United States. Please call in five to 10 minutes
prior to the scheduled start time. A live webcast will also be available
at www.providentenergy.com. A replay of the conference call will be
available on Provident's website and by dialing (416) 695-5275 or
1-866-518-1010.

Provident Energy Trust is a Calgary-based, open-ended energy trust that
owns and manages oil and gas production businesses and a midstream
services business. Provident's energy portfolio is located in some of
the more 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.

Management's discussion and analysis

The following analysis provides a detailed explanation of Provident's
operating results for the quarter and year ended December 31, 2004
compared to the year ended December 31, 2003 and should be read in
conjunction with the consolidated financial statements of Provident.
This analysis has been prepared using information available up to March
9, 2005.

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 the Los Angeles and
Santa Maria basins in the 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, and markets 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.



Consolidated financial highlights
(000s except per unit amounts)

Quarter ended December 31,
---------------------------------------------------------------------
2004 2003 (%)
(Restated) Change
---------------------------------------------------------------------

Revenue $ 369,435 $ 214,477 (1)

Cash flow from COGP operations (1) $ 30,273 $ 21,620 40
Cash flow from USOGP operations(1) $ 11,525 $ - -
Cash flow from midstream services
and marketing (1) $ 16,573 $ 8,723 90
Total cash flow from $ 58,371 $ 30,343 92
Per weighted average unit
- basic by unit $ 0.41 $ 0.37 11
Declared distributions to
unitholders $ 52,064 $ 32,043 63
Per unit $ 0.36 $ 0.39 (8)

Net income (loss) $ 39,179 $ 17,448 131
Per weighted average unit
- basic $ 0.28 $ 0.21 33
Per weighted average unit
- diluted $ 0.28 $ 0.21 33

Capital expenditures $ 26,471 $ 7,549 251

Property acquisitions $ 64,036 $ - -
Property dispositions $ (6,603) $ - -

Long-term debt $ 432,206 $ 356,573 21
Unitholders' equity $ 1,044,969 $ 564,174 85
Weighted average trust units
and exchangeable shares
outstanding (000s) 141,328 80,926 40
---------------------------------------------------------------------


Year ended December 31,
---------------------------------------------------------------------
2004 2003 (%)
(Restated) Change
---------------------------------------------------------------------

Revenue $ 1,109,857 $ 406,329 173

Cash flow from COGP operations (1) $ 121,144 $ 119,561 1
Cash flow from USOGP operations(1) $ 21,458 $ - -
Cash flow from midstream services
and marketing (1) $ 42,644 $ 8,804 384
Total cash flow from $ 185,246 $ 128,365 44
Per weighted average unit
- basic by unit $ 1.59 $ 1.88 (15)
Declared distributions to
unitholders $ 164,628 $ 129,612 27
Per unit $ 1.44 $ 2.06 (30)

Net income (loss) $ 21,682 $ 23,439 (7)
Per weighted average unit
- basic 0.19 $ 0.34 (44)
Per weighted average unit
- diluted $ 0.19 $ 0.34 (44)

Capital expenditures $ 76,321 $ 31,628 141

Property acquisitions $ 72,745 $ - -
Property dispositions $ (13,717) $ (9,947) 38

Long-term debt $ 432,206 $ 356,573 21
Unitholders' equity $ 1,044,969 $ 564,174 85
Weighted average trust units
and exchangeable shares
outstanding (000s) 116,628 68,448 70
---------------------------------------------------------------------
(1) see the MD&A for a definition of cash flow.
---------------------------------------------------------------------


Operational highlights
(000s except per unit amounts)

Quarter ended Year ended
December 31, December 31,
---------------------------------------------------------------------
COGP and (%) (%)
USOGP combined 2004 2003 Change 2004 2003 Change
---------------------------------------------------------------------

Daily production
Light/medium
crude oil (bpd) 14,012 6,454 117 10,146 6,812 49
Heavy oil (bpd) 6,536 7,151 (9) 6,608 6,902 (4)
Natural gas
liquids (bpd) 1,770 1,145 55 1,494 1,167 28
Natural gas (mcf) 7,339 68,657 (100) 77,022 74,596 3
Oil equivalent
(boed)(1) 36,874 26,193 41 31,085 27,314 14

Average selling
price (before hedging)
Light/medium
crude oil
($/bbl) $ 45.83 $ 32.79 40 $ 45.01 $ 36.02 25
Heavy oil
($/bbl) $ 25.33 $ 20.61 23 $ 28.72 $ 24.74 16
Corporate oil
blend ($/bbl) $ 39.31 $ 26.39 49 $ 38.59 $ 30.77 25
Natural gas
liquids
($/bbl) $ 42.80 $ 34.48 24 $ 40.68 $ 35.87 13
Natural gas
($/mcf) $ 6.56 $ 5.62 17 $ 6.60 $ 6.63 -
Oil equivalent
($/boe)(1) $ 39.50 $ 29.95 32 $ 39.12 $ 34.88 12

Netback ($/boe)
before hedging $ 22.33 $ 14.99 49 $ 22.18 $ 20.10 10
Netback ($/boe)
after hedging $ 16.58 $ 12.95 28 $ 16.31 $ 15.19 7
---------------------------------------------------------------------

Midstream
services and
marketing
Redwater
throughput
(bpd) 56,452 63,616 (11) 55,120 N/A -
EBITDA
(thousands) $ 17,957 $ 10,242 75 $ 50,085 $ 10,242 389
---------------------------------------------------------------------
(1) Provident reports barrels of oil equivalent production converting
natural gas to oil on a 6:1 basis
---------------------------------------------------------------------


Fourth quarter highlights

The fourth quarter highlights section provides commentary on the fourth
quarter 2004 results compared to the fourth quarter of 2003. Definitions
of terms used in this section, as appropriate, are defined in the year
over year section of the Management's Discussion and Analysis following
later in this press release.



Consolidated cash flow from operations and cash distributions

Three months ended December 31,
---------------------------------------------------------------------
(000s except for per unit data) 2004 2003
---------------------------------------------------------------------
Revenue, Cash Flow and Distributions (Restated)
Revenue (net of royalties and
non-hedging derivative instruments) $ 369,435 $ 214,477
Cash flow from Operations $ 58,371 $ 30,343
Per weighted average unit - basic(1) $ 0.41 $ 0.63
--------------------------------

Declared distributions $ 52,064 $ 32,024
Per unit(2) $ 0.36 $ 0.39

---------------------------------------------------------------------
Percent of cash flow distributed 89% 105%
---------------------------------------------------------------------

(1) includes exchangeable shares
(2) excludes exchangeable shares


Fourth quarter 2004 cash flow was $58.4 million, 93 percent above the
$30.3 million of cash flow recorded in the fourth quarter of 2003. COGP
2004 fourth quarter cash flow was $30.3 million, 40 percent above the
$21.6 million recorded in the comparable 2003 quarter. The main driver
for this increase was the 41 percent increase in production volumes. The
Midstream business unit added $16.6 million to fourth quarter 2004 cash
million, 90 percent above the $8.7 million recorded in the comparable
2003 quarter. The Midstream cash flow benefited from efficient
operations, marketing opportunities and increased revenues associated
with storage and distribution services. Cash flow from operations also
reflects $11.5 million of USOGP cash flow with no comparative for the
like 2003 quarter.

Declared distributions in the fourth quarter of 2004 totaled $52.1
million, 89 percent of cash flow from operations. This compares to $32.0
million of declared distributions in 2003 that exceeded cash flow by
five percent.

Comparative figures for cash flow from operations and cash flow per unit
for the fourth quarter of 2003 have been restated to reflect the
retroactive application of reclassifying the convertible debentures to
debt and netting $3.0 million of debenture interest from cash flow from
operations.



Net income

Three months ended December 31,
---------------------------------------------------------------------
(000s except for per unit data) 2004 2003
---------------------------------------------------------------------
(Restated)
Net income $ 39,179 $ 17,448
Per weighted average unit
- basic(1) $ 0.28 $ 0.22
Per weighted average unit
- diluted(2) $ 0.28 $ 0.22
---------------------------------------------------------------------

(1) Based on weighted average number of trust units and trust units
that would be issued upon conversion of exchangeable shares. Net
income available for distribution to unitholders in the basic and
diluted per trust unit calculations has been reduced by interest
on the convertible debentures.
(2) Based on weighted average number of trust units and trust units
that would be issued upon conversion of exchangeable shares and
conversion of the convertible debentures.



Net income for the fourth quarter of 2004 increased 124 percent to $39.2
million compared to a $17.4 million of net income in the comparable 2003
quarter. The fourth quarter earnings reflect the impact of non-hedging
derivative instruments on COGP results as well as significant income
generated from the Midstream business unit.

The COGP business segment contributed $27.6 million of net income, $16.8
million above 2003 fourth quarter income of $9.8 million (as restated).
The increase in the fourth quarter of 2004 highlights the impact of
Accounting Guideline 13 "hedging relationships". The guideline
contradicts the matching principal applied in accounting that requires
revenues to be recognized with expenses incurred in a period. As a
result of the guideline, $25 million of pre-tax COGP income was recorded
due to the reduction in unrealized hedging losses (disclosed as
financial derivative instruments recorded on the balance sheet in the
quarter accompanied by twelve months of operations). In summary, the
total hedging loss recorded at September 30 against nine months of
operations totaled $97.8 million, including an unrealized loss of $47.1
million compared to $91 million of hedging loss booked against twelve
months of operations including only $22.1 million of unrealized losses.

The Midstream unit contributed $11.1 million of net income in the fourth
quarter of 2004, as compared to the $7.7 million of net income in the
fourth quarter of 2003.

USOGP contributed $0.5 million of net income in the fourth quarter of
2004 with no comparative for 2003.

Comparative figures for fourth quarter 2003 net income have been
restated to reflect the retroactive application of the new standard on
accounting for convertible debentures that resulted in a reduction to
net income of $3.6 million.



Taxes

Three months ended December 31,
---------------------------------------------------------------------
($000s) 2004 2003
---------------------------------------------------------------------

Capital taxes $ 2,547 $ 887
Current and withholding taxes 664 -
Future income taxes recovery $ (10,000) $ (23,241)
---------------------------------------------------------------------
---------------------------------------------------------------------


Capital taxes in the fourth quarter totaled $2.5 million, an increase
$1.6 million above the $0.9 million recorded in the fourth quarter of
2003. The increase reflects the impact the growth in our Canadian asset
base has had on the paid up capital of Provident as well as the increase
in the Saskatchewan resource surcharge that is sensitive to crude oil
prices.

The current and withholding taxes total $0.7 million in the fourth
quarter of 2004 with no comparative balance in the comparable 2003
quarter. These taxes arise from Provident's U.S. based operations.

The 2004 fourth quarter future tax recovery of $10.0 million compares to
a $23.2 million future tax recovery in the fourth quarter of 2003. A
significant recovery occurred in the fourth quarter of 2003 due the
determination of internal royalty charges that moved more projected
future taxes into lower tax rate years, resulting in a larger recovery.



Interest expense

Three months ended December 31,
---------------------------------------------------------------------
($000s) 2004 2003
---------------------------------------------------------------------

Interest on long-term bank debt $ 3,734 $ 2,941
Interest on debentures 3,612 2,966
---------------------------------------------------------------------
Total cash interest 7,346 5,907
Non-cash accretion and amortization
on convertible debentures (292) 653
Total interest including accretion
and amortization on convertible debentures $ 7,054 $ 6,560
---------------------------------------------------------------------
---------------------------------------------------------------------


Cash interest expense increased for the quarter as compared to the same
quarter in 2003 due to the increase in the overall size of Provident,
with commensurate increases in debt levels. Accretion and amortization
on convertible debentures has resulted from Provident early adopting and
reclassifying the bulk of its subordinated convertible debentures to
long-term debt and an additional portion to equity. The accounting
treatment for these non-cash amounts is more fully discussed in the year
over year section of Management's Discussion and Analysis.

Commodity Price Risk Management Program (CPRMP)

In the fourth quarter of 2004 the opportunity cost of hedging amounted
to $18.3 million compared to $4.9 million of costs in the comparable
quarter in 2003.

The COGP business unit recorded a fourth quarter 2004 opportunity cost
of $16.5 million on crude oil ($ 11.35 per barrel) and an opportunity
cost of $2.0 million on natural gas ($0.25 per mcf), compared to an
opportunity cost of $3.9 million for crude oil ($3.12 per barrel) and an
opportunity cost of $1.0 million for natural gas ($0.16 per mcf) in the
comparable quarter in 2003.

The USOGP business unit recorded an opportunity cost of $0.1 million
($0.18 per barrel) in the quarter, all related to crude oil with no
comparative figure for 2003.

The Midstream business unit recorded a gain of $0.3 million in the
quarter primarily on propane and ethane price stabilization hedging
activities. The Midstream unit did not have any hedging activity for the
fourth quarter of 2003.

Foreign exchange hedges have been allocated to the commodity the hedge
related to at the initiation of the transaction.

Provident's Commodity Price Risk Management Program is more fully
discussed in the year over year section of Management's Discussion and
Analysis.



COGP segment review

Crude oil price

COGP Three months ended December 31,
---------------------------------------------------------------------
%
($ per bbl) 2004 2003 change
---------------------------------------------------------------------

Oil per barrel
WTI (US$) $ 48.27 $ 31.18 55
Exchange rate (from US$ to Cdn$) $ 1.21 $ 1.32 (8)
WTI expressed in Cdn$ $ 58.41 $ 41.16 42
Corporate realized crude oil and natural
gas liquids price before hedging (Cdn$) $ 35.86 $ 27.02 33

Corporate realized light/medium oil price
before hedging (Cdn$) $ 42.00 $ 32.79 28

Corporate realized heavy oil price before
hedging (Cdn$) $ 25.33 $ 20.61 23
Corporate realized natural gas liquids
price before hedging (Cdn$) $ 42.66 $ 34.48 24

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


Provident's realized oil and natural gas liquids price, prior to the
impact of hedging, increased by 33 percent to $35.86 per barrel in the
fourth quarter of 2004 compared to $27.02 per barrel in the fourth
quarter of 2003. The 2004 increase related to a higher US dollar WTI
crude oil price offset by a stronger Canadian dollar.

For 2004, the 55 percent increase in WTI did not lead to a commensurate
increase in Provident's realized oil and natural gas liquids price,
prior to the impact of hedging, as Provident's price was eroded by the
stronger Canadian dollar partially offset by a decreased percentage of
production of lower priced heavy oil. Fourth quarter heavy oil
production as a percentage of total crude oil and natural gas liquids
production in 2004 was 37 percent compared to 48 percent of total crude
oil and natural gas liquids production in the comparable 2003 quarter.
The decrease in the year over year percentage of heavy oil production
was mainly due to the effect of the Viracocha and Olympia acquisitions,
and drilling results.



Natural gas price

COGP Three months ended December 31,
---------------------------------------------------------------------
%
2004 2003 change
---------------------------------------------------------------------

AECO (Cdn$) per mcf $ 7.07 $ 5.59 32
Gas revenue per mcf (1)(Cdn$) $ 6.53 $ 5.62 16

(1) Excluding the effects of the commodity price risk management
program
---------------------------------------------------------------------

Provident's realized natural gas price, excluding hedges, increased
16 percent in the fourth quarter of 2004 as compared to the fourth
quarter of 2003.


Production

COGP Three months ended December 31,
---------------------------------------------------------------------
%
2004 2003 change
---------------------------------------------------------------------

Daily production
Crude oil - Light/Medium (bpd) 9,281 6,454 44
- Heavy (bpd) 6,536 7,151 (9)
Natural gas liquids (bpd) 1,746 1,145 52
Natural gas (mcfd) 85,803 68,657 25
Oil equivalent (boed) (1) 31,864 26,193 22


The 2004 fourth quarter 22 percent increase in daily production to
31,864 boed compared to 26,193 boed in the fourth quarter of 2003
reflects the acquisition of Olympia and Viracocha to the COGP production
base as well as drilling and optimization activities offset by natural
production declines.



Revenue and royalties

Revenue figures are presented net of transportation expense.

COGP Three months ended December 31,
---------------------------------------------------------------------
%
2004 2003 change
---------------------------------------------------------------------
Oil
Revenue $ 51,125 $33,034 55
Cash hedging (16,511) (3,910) (322)
Royalties (net of ARTC) (10,230) (6,475) (58)
---------------------------
Net revenue $ 24,384 $22,649 8
---------------------------
---------------------------
Net revenue (per barrel) $ 16.41 $ 18.09 (9)
Royalties as a percentage of revenue 20.0% 19.6% 2

Natural gas
Revenue $ 51,637 $35,724 46
Cash hedging (2,001) (925) (119)
Amortization of deferred hedging - (84) -
Royalties (net of ARTC) (11,107) (7,237) (53)
---------------------------
Net revenue $ 38,529 $27,478 40
---------------------------
---------------------------
Net revenue (per mcf) $ 4.95 $ 4.35 14
Royalties as a percentage of revenue 21.5% 20.3% 6

Natural gas liquids
Revenue $ 6,852 $ 3,630 89
Royalties (1,464) (888) (65)
---------------------------
Net revenue $ 5,388 $ 2,742 96
---------------------------
---------------------------
Net revenue (per barrel) $ 33.54 $ 26.04 29
Royalties as a percentage of revenue 21.4% 24.5% (13)

Total
Revenue $109,614 $72,388 51
Cash hedging (18,512) (4,835) (283)
Amortization of deferred hedging - (84) -
Royalties (net of ARTC) (22,801) (14,600) (56)
---------------------------
Net revenue $ 68,301 $52,869 29
---------------------------
---------------------------
Net revenue per boe $ 23.03 $ 21.94 5
Royalties as a percentage of revenue 20.8% 20.2% 3


Quarter over quarter COGP production revenue has increased by 51 percent
to $109.6 million from $72.4 million in 2003. The increase incorporates
the 22 percent increase in production volumes, and a 55 percent increase
in WTI crude oil price partially offset by wider differentials in the
quarter. Royalties as a percentage of revenue have remained relatively
constant at 20.8 percent compared to 20.2 percent for the like quarter
in 2003. Net revenue at $68.3 million is 29 percent above the $52.9
million recorded in fourth quarter 2003. This reflects the increase in
production volumes and crude oil prices offset by a $13.7 million
increase in costs associated with hedging activities.



Production expenses

COGP Three months ended December 31,
---------------------------------------------------------------------
%
($000s except per boe amounts) 2004 2003 change
---------------------------------------------------------------------
Production expenses $26,431 $21,653 22
Production expenses (per boe) $ 9.02 $ 8.99 -
---------------------------------------------------------------------


Fourth quarter production expenses increased 22 percent to $26.4 million
from $21.7 million in fourth quarter of 2003. The increase coincides
with the equivalent increase in production volumes. On a boe basis
quarter over quarter production expenses are flat. This recognizes the
increase in production volumes absorbing the fixed cost component of
operating costs over a greater volume of barrels of oil equivalent
production offset by an increase in industry costs driven by high
commodity prices.

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. Fourth quarter non-cash general and administrative expenses
for COGP totaled $0.9 million.



COGP Three months ended December 31,
---------------------------------------------------------------------
%
($000s except per unit data) 2004 2003 change
---------------------------------------------------------------------

Cash general and administrative $ 3,918 $ 4,244 (8)

Cash general and administrative per boe $ 1.34 $ 1.76 (24)
---------------------------------------------------------------------


Cash general and administrative expenses for COGP in the fourth quarter
decreased eight percent to $3.9 million from $4.2 million recorded in
the 2003 comparable quarter. On a boe basis the cash general and
administrative expenses recorded in fourth quarter 2004 decreased 24
percent to $1.34 from $1.76 in the fourth quarter of 2003. For the
fourth quarter of 2004 both the absolute dollars and the per boe charges
incorporate a reclassification of overhead and certain direct charges
that should have been recorded as expenses in the Midstream and USOGP
business units in prior quarters.



Operating netback

COGP Three months ended December 31,
---------------------------------------------------------------------
%
2004 2003 change
---------------------------------------------------------------------
Netback per boe
Gross production revenue $ 37.29 $ 30.04 24
Royalties (net of ARTC) (7.78) (6.06) 28
Operating costs (9.02) (8.99) -
--------------------------
Field operating netback 20.49 14.99 37

Realized loss on cash hedging (6.32) (2.01) 214
--------------------------
Operating netback after hedging $ 14.18 $ 12.98 9
--------------------------
--------------------------

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


The fourth quarter 2004 field operating netback of $20.49 per boe was 37
percent above the $14.99 per boe in the same quarter in 2003. The
increased field operating netback in the fourth quarter of 2004 reflects
a higher WTI crude oil benchmark partially offset by wider differentials
as well as a significant shift in Provident's production mix to include
a greater weighting towards natural gas and lighter grades of crude oil.
Operating netbacks after hedging increased by only eight percent to
$14.18 from $12.98 reflecting the fourth quarter opportunity cost due to
hedging of $6.32 per boe compared to $2.01 in the comparable quarter in
2003.



Capital expenditures

COGP Three months ended December 31,
---------------------------------------------------------------------
($000s) 2004 2003
---------------------------------------------------------------------

Lloydminster $ 4,799 $ 1,469
West central and southern Alberta 8,413 3,298
Southeast and southwest Saskatchewan 8,201 1,894
Office and other 185 891
--------------------------
Total additions $21,598 $ 7,552
--------------------------
--------------------------

--------------------------
Dispositions (1) $ 6,603 $ -
--------------------------
--------------------------

---------------------------------------------------------------------
(1) Includes $3.0 million of non cash proceeds.
---------------------------------------------------------------------


Provident spent $21.6 million during the fourth quarter of which $4.8
million was spent in the Lloydminster core area drilling wells and
optimizing production through pump upgrades. Operated and non-operated
drilling projects combined with re-completion and facility projects
accounted for $8.4 million of spending in west central and southern
Alberta. The Trust also spent $8.2 million in southeast and southwest
Saskatchewan on shallow gas development, several re-completion projects,
facility work and land purchases.

Provident experienced weather related delays on capital projects
throughout the fourth quarter of 2004. Planned capital expenditures of
approximately $5.9 million have been deferred to 2005.

Provident spent $7.6 million in the fourth quarter of 2003 on various
drilling, recompleting, optimization and facility projects.

U.S. OGP segment

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 and, therefore there are no fourth quarter
comparative figures for 2003.



Crude oil price

($ per bbl) Three months ended December 31,
---------------------------------------------------------------------
USOGP 2004
---------------------------------------------------------------------
USOGP realized crude oil and natural
gas liquids price before hedging (Cdn$) $ 52.59

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

The USOGP crude oil production, represents 94 percent of the
production mix and is primarily light, sweet crude which attracts
prices with a very small ($0.60 per barrel) differential to benchmark
prices.


Production

Three months ended December 31,
---------------------------------------------------------------------
USOGP 2004
---------------------------------------------------------------------
Daily production
Crude oil - Light/Medium (bpd) 4,730
Natural gas liquids (bpd) 24
Natural gas (mcfd) 1,536
Oil equivalent (boed) (1) 5,010
---------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to
oil on a 6:1 basis.


USOGP production increased 1,441 boe per day in the fourth quarter of
2004 when compared to the third quarter of 2004. The increase is
primarily attributable to the Orcutt acquisition which added 1,425 boe
day for the period October 4 to December 31, 2004. The exit production
rate for 2004 was approximately 5,200 boe per day.

Revenue and royalties

The following table outlines USOGP revenue and royalties by product
line. The table excludes revenues earned from operating certain
properties ($0.3 million) on behalf of third parties.



USOGP Three months ended December 31,
---------------------------------------------------------------------
($000s except per unit data) 2004
---------------------------------------------------------------------
Oil
Revenue $ 23,212
Realized loss on non-hedging derivative instrument (81)
Royalties (2,041)
---------------------------------------------------------------------
Net revenue $ 21,090
---------------------------------------------------------------------
Net revenue (per barrel) $ 40.46
Royalties as a percentage of revenue 8.8%

Natural gas
Revenue $ 1,134
Realized loss on non-hedging derivative instrument -
Royalties -
---------------------------------------------------------------------
Net revenue $ 1.134
---------------------------------------------------------------------
Net revenue (per mcf) $ 6.56
Royalties as a percentage of revenue -

Natural gas liquids
Revenue $ 118
Royalties -
---------------------------------------------------------------------
Net revenue $ 118
---------------------------------------------------------------------
Net revenue (per barrel) $ 52.23
Royalties as a percentage of revenue -

Total
Revenue $ 24,464
Realized loss on non-hedging derivative instrument (81)
Royalties (2,041)
---------------------------------------------------------------------
Net revenue $ 22,342
---------------------------------------------------------------------
Net revenue per boe $ 41.35
Royalties as a percentage of revenue 8.3
---------------------------------------------------------------------
Note: the above figures are presented net of transportation expenses.


Production expenses

USOGP Three months ended December 31,
---------------------------------------------------------------------
($000s) except per unit amounts 2004
---------------------------------------------------------------------
Production expenses $ 6,989
Production expenses (per boe) $ 15.16
---------------------------------------------------------------------


Production expenses were higher than expected in the period fourth
quarter of 2004 due to less than expected incremental production from
drilling activities as well as the continued increase in the cost of
goods and services driven by the high commodity price environment.
Operating costs were also impacted by a number of higher operating cost
crude oil wells that were returned to production to take advantage of
high crude oil prices.

When compared to the third quarter of 2004, operating costs have
decreased by $0.66 per boe, or 4 percent, due to the fixed cost
component of the operating costs being spread out over more barrels.



General and administrative

USOGP Three months ended December 31,
---------------------------------------------------------------------
($000s) except per unit amounts 2004
---------------------------------------------------------------------
Cash general and administrative $ 2,264
Cash general and administrative per boe $ 4.91
---------------------------------------------------------------------

Cash general and administrative expenses in the fourth quarter at
$2.3 million or $4.91 per boe include additional expenses for costs
that were not adequately accrued from acquisition date to September
30, 2004.


Operating netback

USOGP Three months ended December 31,
---------------------------------------------------------------------
($ per boe) 2004
---------------------------------------------------------------------
Netback
Gross production revenue $ 53.08

Royalties (4.43)
Operating costs (15.16)
---------
Field operating netback 33.49

Cash hedging (0.18)
---------
Operating netback after hedging $ 33.31
---------------------------------------------------------------------
---------------------------------------------------------------------


Operating netbacks in the fourth quarter of 2004 remain strong driven by
high commodity prices partially offset by increased operating costs.



Income taxes and cash taxes

USOGP Three months ended December 31,
---------------------------------------------------------------------
($000s) 2004
---------------------------------------------------------------------

Current and withholding taxes $ 718

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


Current and withholding taxes include current US federal and state
income taxes as well as accrued or paid US withholding taxes on payments
that have been or will be made from Breitburn Energy LP to Provident.

Capital expenditures

USOGP capital expenditures for the fourth quarter of 2004 totaled $63.1
million. This includes $58.5 million for the Orcutt property
acquisition, $3.1 million to increase Breitburn's working interest in
certain wells at West Pico and Sawtelle, and $1.5 million on drilling,
optimization and facility upgrades at West Pico and Santa Fe Springs.
Optimization capital was partially focused at returning previously
uneconomic wells to production to take advantage of the high commodity
price environment.

Midstream services and marketing

The fourth quarter of 2004 results for the Midstream services and
marketing business unit reflected in EBITDA, cash flow and net income
benefited from efficient operations, marketing opportunities and
increased revenues associated with storage and distribution services.
Fourth quarter 2004 EBITDA of $18.0 million increased 753 percent from
$10.1 million in the year ago quarter. Cash flow for the fourth quarter
of 2004 quarter was $16.6 million 89 percent above the $8.8 million for
the fourth quarter 2003. Fourth quarter net income at $11.1 million was
44 percent above the $7.7 million of net income recorded in the fourth
quarter of 2003.



2004 year end results

Consolidated cash flow from operations and cash distributions

Year ended December 31,
($ 000s, except per unit data) 2004 2003
---------------------------------------------------------------------
Revenue, Cash Flow and Distributions (Restated)
Revenue (net of royalties and non-hedging
derivative instruments - see Note 7 of
the financial statements) $ 1,109,857 $ 406,329

Cash flow from operations before changes
in working capital and site restoration
expenditures $ 185,246 $ 128,365
Per weighted average unit - basic (1) 1.59 1.88
Per weighted average unit - diluted (1) 1.59 1.88
Declared distributions $ 164,628 $ 129,612
Per Unit - actual (2) 1.44 2.06
Percent of cash flow distributed 89% 101%

(1) includes exchangeable shares
(2) excludes exchangeable shares


For the year ended December 31, 2004, cash flow increased 44 percent or
$56.9 million to $185.2 million from $128.3 million for 2003 (per unit
in 2004 - $1.59 in 2003 - $1.88). COGP generated $121.1 million, USOGP
$21.5 million, and Midstream $42.6 million of cash flow during 2004.

During 2003 COGP generated cash flow of $119.6 million, while Midstream,
owned only for the fourth quarter of 2003, generated cash flow of $8.8
million and there was no USOGP comparative.

A full year of results from the Midstream business unit accounted for
$33.8 million of the increase in cash flow. Combined oil and gas
operations contributed $23.1 million of the cash flow increase a result
of a 14 percent increase in oil and gas production combined with higher
crude oil prices largely offset by opportunity costs associated with the
Commodity Price Risk Management Program. Opportunity costs under the
Commodity Price Risk Management Program include a $3.2 million cost for
Midstream as well as an increase in 2004 for the oil and gas production
business segments to $5.78 per boe from $4.91 per boe in 2003. Per trust
unit, the cost decreased to $0.59 per unit in 2004 from $0.71 in 2003
($68.9 million and $48.9 million respectively).

Declared distributions in 2004 totaled $164.6 million, 89 percent of
cash flow from operations. This compares to $129.6 million of declared
distributions in 2003 that exceeded cash flow by one percent.
Provident's objective in 2005 is to distribute between 80 and 95 percent
of cash flow as distributions to unitholders.

Management uses cash flow (before changes in non-cash working capital
and site restoration expenditures) to analyze operating performance.
Provident also reviews cash flow in setting monthly distributions and
takes into account cash required for debt repayment and/or capital
programs in establishing the amount to be distributed. Historically
Provident has paid out between 89 percent and 102 percent of its annual
cash flow as distributions to unitholders.

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 calculation 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 Canadian GAAP. All references to cash flow
throughout this report are based on cash flow before changes in non-cash
working capital.



Distributions

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


---------------------------------------------------------------------
Distribution Amount
Record Date Payment Date (Cdn$) (US$)(1)
---------------------------------------------------------------------
2004
January 22, 2004 February 13, 2004 $0.12 $0.09
February 19, 2004 March 15, 2004 0.12 0.09
March 19, 2004 April 15, 2004 0.12 0.09
April 20, 2004 May 14, 2004 0.12 0.09
May 19, 2004 June 15, 2004 0.12 0.09
June 18, 2004 July 15, 2004 0.12 0.09
July 20, 2004 August 13, 2004 0.12 0.09
August 20, 2004 September 15, 2004 0.12 0.09
September 20, 2004 October 15, 2004 0.12 0.09
October 20, 2004 November 15, 2004 0.12 0.09
November 19, 2004 December 15, 2004 0.12 0.10
December 20, 2004 January 15, 2005 0.12 0.10
---------------------------------------------------------------------

2004 Cash Distributions paid as declared $1.44 $1.10
---------------------------------------------------------------------

2003 Cash Distributions paid as declared $2.06 $1.47

2002 Cash Distributions paid as declared $2.03 $1.29

2001 Cash Distributions paid as declared
- March 2001 - December 2001 $2.54 $1.64

---------------------------------------------------------------------
Inception to December 31, 2004
- Distributions paid as declared $8.07 $5.50

---------------------------------------------------------------------
(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. The 2003 comparables were 59 percent and
41 percent respectively. Distributions received by U.S. resident
unitholders in 2004 are classified as 83 percent qualified dividend and
17 percent tax deferred return of capital. The 2003 comparables were 73
percent and 27 percent respectively. In both the 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.



Net income

Year ended December 31,
---------------------------------------------------------------------
(000s, except per unit data) 2004 2003
---------------------------------------------------------------------
(Restated)
Net income $ 21,682 $ 23,439
Per weighted average unit
- basic (1) $ 0.19 $ 0.34
Per weighted average unit
- diluted(2) $ 0.19 $ 0.34
---------------------------------------------------------------------

(1) Based on weighted average number of trust units outstanding plus
the number of trust units that would be issued upon conversion of
exchangeable shares.
(2) Based on weighted average number of trust units and trust units
that would be issued upon conversion of exchangeable shares,
conversion of the convertible debentures and pursuant to the unit
option plan.


Year ended December 31,
---------------------------------------------------------------------
($000s) 2004 2003
---------------------------------------------------------------------
(Restated)
COGP net income (loss) $ (20,551) $ 15,728
USOGP net income 9,699 -
-----------------------------
Total oil and gas net income (10,852) 15,728
Midstream net income 32,534 7,711

---------------------------------------------------------------------
Net income $ 21,682 $ 23,439
---------------------------------------------------------------------
---------------------------------------------------------------------


For the year ended December 31, 2004, consolidated earnings of $21.7
million resulted from Midstream and Marketing and USOGP net income of
$32.5 million and $9.7 million, respectively, offset by a $20.6 million
loss in COGP.

Net income of $32.5 million in the Midstream business unit reflects a
full year of successful operations incorporating Provident's strategy of
achieving a lower risk cash flow stream and the operational efficiencies
achieved by Provident's Midstream unit. The segment has not been
materially impacted by any year over year changes in accounting policies.

The net combined loss for the year for COGP and USOGP of $10.9 million
compares to net income in 2003 of $15.7 million. Comparability to prior
years is difficult largely due to the implementation of CICA Accounting
Guideline 13, "Hedging relationships" and no comparative figures for
USOGP from 2003. Provident did not apply hedge accounting to the
Commodity Price Risk Management Program and therefore has marked to
market the outstanding derivatives at each quarter end throughout the
year. As discussed in the quarter over quarter analysis, this has had a
significant effect on quarterly reporting of net income. In addition,
under accounting guideline 13, Provident's January 1, 2004 mark to
market opportunity cost position of $25.1 million was set up as a
deferred derivative loss to be amortized as a non-cash expense over the
life of those derivatives. Amortization of this amount during 2004
resulted in a further non-cash charge of $23.0 million in 2004. The
combined net non-cash pre-tax charge for the year ended December 31,
2004, attributed to accounting guideline 13 was $22.1 million. On an
after tax basis the impact was $13.6 million for the year ended December
31, 2004. In future periods, the non-cash mark to market expense or
recovery (recorded as loss or gain on non-hedging derivative
instruments) may be significant depending on Provident's derivative
portfolio and the change in market prices during those periods.

In 2003 consolidated net income of $23.4 million was generated by COGP
net income of $15.7 million and Midstream income of $7.7 million. COGP
income was reduced by an $18.6 million non-cash charge associated with
the management internalization offset by a $55.1 million future tax
recovery that resulted from changes to Canadian tax legislation.
Further, the 2003 comparative figures for net income have been restated
for the retroactive application of the reclassification of debentures to
long-term debt resulting in an increase in interest expense and
amortization of debt issue costs.



Taxes

Year ended December 31,
---------------------------------------------------------------------
($000s) 2004 2003
---------------------------------------------------------------------

Capital taxes $ 5,921 $ 3,332
Current and withholding taxes 1,282 -
Future income taxes (recovery) (40,577) (56,478)
---------------------------------------------------------------------
$ (33,374) $ (53,146)
---------------------------------------------------------------------


Future income taxes arise as a result of the difference between the
accounting and tax bases of the operating companies and subsidiaries.
Payments to the Trust by these subsidiaries are deductible for income
taxes. The Trust is a taxable entity under the Income Tax Act (Canada)
and is taxable only on income that is not distributed or distributable
to the unitholders. As the Trust distributes all of its taxable income
to the unitholders and meets the requirements of the Income Tax Act
(Canada) applicable to the Trust, no provision for income taxes has been
made in the Trust.

The 2004 future income tax recovery of $40.6 million compares to a $56.5
million recovery for the comparable 2003 period. In 2004, the year to
date recovery reflects the losses recorded due to Accounting Guideline
13 in respect of hedging relationships. Recoveries in both years reflect
the deductibility of payments to the Trust by the operating companies
and subsidiaries. The recovery reported in 2003 reflects the federal tax
rate reduction from the 2003 federal budget that reduced federal tax
rates on resource profits in future years.

Capital taxes include the Saskatchewan Resource surcharge and federal
and provincial large corporation taxes. Current and withholding taxes
reflect U.S. taxes that are incurred on operations associated with
Provident's June 15, 2004 acquisition of U.S. based BreitBurn Energy.
U.S. operations are subject to U.S. federal and state income taxes.
Payments from U.S. entities to Canadian entities are subject to
withholding taxes if the distributions are characterized by U.S. tax
authorities as income or interest.



Interest expense

Year ended December 31,
---------------------------------------------------------------------
(000s, except per unit data) 2004 2003
---------------------------------------------------------------------

Interest on bank debt $ 11,816 $ 9,733
Weighted-average interest rate on bank debt 3.96% 4.30%

Interest on 10.5% convertible debentures 5,226 5,687

Interest on 8.75% convertible debentures 6,421 1,654

Interest on 8.0% convertible debentures 2,153 -
--------------------------

Total cash interest 25,616 17,074
--------------------------
Weighted average interest rate on all
long-term debt 6.05% 4.86%

Non-cash accretion and amortization
- convertible debentures
Accretion expense 1,373 1,797
Amortization of deferred debt issue costs 1,435 817

--------------------------
Total interest including accretion and
amortization on convertible debentures $ 28,424 $ 19,688
--------------------------


Interest expense increases for the year reflect both increased debt
levels as a result of corporate growth and a change in accounting policy
that reclassified convertible debentures to long-term debt, excluding a
minor equity component.

Effective December 31, 2004, the Trust retroactively adopted the revised
CICA Handbook Section 3860, ("HB 3860"), "Financial Instruments -
presentation and disclosure", for finanical 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 obligation in exchange for the trust units.

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.

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. These financing charges are
amortized to income on a straight line basis. 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 at $48.1
million which is fair value under accounting rules. The difference
between the fair value and proceeds of $1.9 million was recorded as
equity.

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. These financing
charges are amortized to income on a straight line basis. 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.

On April 11, 2002 the Trust issued $64.4 million of unsecured
subordinated convertible debentures ($61.4 million net of issue costs)
with a 10.5 percent coupon rate maturing May 15, 2007. Issue costs have
been classified as deferred financing charges. These financing charges
are amortized to income on a straight line basis. The debentures may be
converted into trust units at the option of the holder at a conversion
price of $10.70 per trust unit prior to May 15, 2007, 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 $63.2 million. The difference between
the fair value and proceeds of $3.7 million was recorded as equity.

Financial instruments

Commodity price risk management program

For the year ended December 31, 2004 an opportunity cost of $68.9
million was recorded due to the Commodity Price Risk Management Program
with $65.7 million related to the combined oil and gas operations and
$3.2 million associated with the midstream business unit.

In the oil and gas business units the hedging cost associated with crude
oil totaled $55.3 million ($9.03 per barrel) and $10.4 million related
to natural gas ($0.37 per mcf), combined total was $65.7 million or
$5.78 per boe. This loss includes gains of $3.3 million realized on
heavy oil differential contracts. In 2003 the program recorded an
opportunity cost of $48.9 million or $4.91 per boe with $23.9 million
related to crude oil ($4.77 per barrel) and $25.0 million related to
natural gas ($0.92 per mcf).

In 2004 the Midstream business unit recorded an opportunity cost of $3.2
million primarily on propane and ethane price stabilization hedging
activities with no comparative for 2003.

Realized gains and losses on foreign exchange contracts which fixed the
exchange rates on foreign currency contracts related to the commodity
price management program have been presented in the hedging totals of
the commodities to which the foreign exchange contract related at the
time of entering the contract.

On a per trust unit basis the opportunity cost of the Commodity Price
Risk Management Program decreased to $0.59 per trust unit in 2004 from
$0.71 per trust unit in 2003.

At December 31, 2004 the mark to market value of open contracts was in a
loss position of $24.5 million based on commodity prices prevailing at
that date. This amount has been reflected in the financial statements of
the Trust pursuant to Accounting Guideline 13 and Emerging Issues
Committee Abstract 128 in respect of accounting for financial
instruments.

Provident's Commodity Price Risk Management Program (the "Program")
involves a disciplined hedging strategy that utilizes derivative
instruments to assist with more predictable and stable cash
distributions. The hedging strategy protects a percentage of production
against a decline in commodity prices while, with some products,
allowing the Trust to participate in a rising commodity price
environment. It provides protection for pricing margin and inventory
values associated with the midstream and marketing business lines. As
well, the strategy reduces Foreign Exchange risk due to the exposure
arising from the conversion of U.S. dollars into Canadian dollars.

We expect continued commodity price volatility in 2005; as a result
Provident will continue to execute the Program. The financial
instruments used to hedge our cash flows will enable Provident to
participate to a greater degree in a rising price market and should
somewhat protect distributions should commodity prices weaken.

The hedging instruments the Trust uses include puts, costless collars,
participating swaps, fixed and indexed referenced pricing.

Acquisitions

Provident completed three major corporate acquisitions during 2004. On
June 1, 2004 Provident closed the concurrent acquisitions of Olympia
Energy Inc, and Viracocha Energy Inc. by way of amalgamations with
Provident Energy Ltd. On June 15, 2004, Provident acquired 92 percent of
BreitBurn Energy LLC (BreitBurn), a private company (now a limited
partnership) active in the oil and gas exploitation and production
business in the Los Angeles basin, U.S.A. The three acquisitions added
$486.5 million to property plant and equipment and $228.5 million to
goodwill. Other asset and liability accounts were also assigned values.
In total, 39.2 million units were issued to finance the three
acquisitions for ascribed values and cash totaling $434.9 million, 2.7
million exchangeable shares were issued for ascribed values totaling
$30.2 million and $50.0 million of convertible unsecured subordinated
debentures were issued as part of the BreitBurn financing. The
transactions have all been accounted for using the purchase method.

On October 4, 2004, Provident, through BreitBurn, closed the acquisition
of certain properties in California (the Orcutt field) for $58.5
million. Provident funded this acquisition for the Breitburn partnership
and as a result increased its investment ownership in BreitBurn by 2.2
percent to a total of 94.2 percent.

On March 2, 2005, Provident, through Breitburn, acquired Nautilus
Resources, LLC (Nautilus) for C$95.8 million (US$77.6 million). Nautilus
is a U.S. private company with operations focused in the Big Horn and
Wind River Basins of Wyoming. Nautilus is currently producing
approximately 2,300 barrels of oil equivalent per day consisting of 99
percent crude oil and one percent natural gas. The BreitBurn team has
experience in the Wyoming basins through their discovery and
exploitation of their Lost Dome field that is located near Nautilus'
assets.

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



Liquidity and capital resources

December 31,
---------------------------------------------------------------------
($000s) 2004 2003
---------------------------------------------------------------------
Long-term debt $ 432,206 $ 356,573
Working capital (surplus)/deficit 38,677 (18,552)
--------------------------
Net debt 470,883 338,021

Equity (at book value) 1,044,969 564,174
--------------------------

Total capitalization at book value $1,515,852 $ 902,195
----------------------------
----------------------------

Net debt as a percentage of total book
value capitalization 31% 37%


Provident operates three business units with similar but not identical
monthly cash settlement cycles. Provident's working capital position is
impacted 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 December 31, 2004 Provident had drawn on 64 percent of its term
credit facility of $410.0 million as compared to 71 percent drawn on its
$335.0 million term credit facility as at December 31, 2003. The
increase in the level of bank debt was due to the increase scale of
operations primarily due to acquisitions. The reduced percentage of the
credit facilities drawn reflects the reduced leverage on the balance
sheet. Provident has grown significantly in 2004 and financed the
majority of 2004 acquisitions with equity. The change in accounting
policy reclassified convertible debentures to long-term debt, excluding
a minor equity component. This accounting change is more fully discussed
in the interest expense section above.

At December 31, 2004 Provident had letters of credit guaranteeing
Provident's performance under certain commercial and other contracts
that totaled $31.0 million, increasing bank line utilization to 72
percent. The guarantees are associated with the Midstream business unit
and at December 31, 2003 totaled $12.3 million.

Provident's working capital decreased by $57.2 million as at December
31, 2004. Of this amount $22.4 million was due to incorporating balance
sheet accounts for unrealized hedging losses as required by the
implementation of Accounting Guideline 13, "Hedging Relationships" and
EIC 128 (see changes in accounting policy in this MD&A), a $7.1 million
decrease in petroleum product inventory, and a $7.0 million increase in
declared distributions payable while the balance was due to changes in
other accounts reflecting the increased scale of activities including
capital activities.

Fourth quarter cash flow in 2004 was $58.4 million. The ratio of debt to
annualized fourth quarter cash flow was 1.85 to one, as compared to
fourth quarter annualized debt to cash flow in 2003 of 2.9 to one.

Trust units and exchangeable shares

In 2004, the Trust issued 1.6 million units (conversion amount $15.3
million) on conversion of exchangeable shares to units and issued 0.1
million units for the quarter (year ended December 31, 2003 - 5.7
million units with a conversion amount of $55.5 million). The Trust also
issued 11,378 units on conversion of convertible debentures and 0.6
million units pursuant to the stock option plan. Details of these issues
are outlined in the notes to the financial statements. 1.9 million units
were issued or are to be issued resulting from Provident's Premium
Distribution, Distribution Reinvestment and Optional Unit Purchase Plan
(DRIP) program (proceeds of $19.9 million) (year ended December 31, 2003
- 2.6 million units for proceeds of $27.4 million).

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. Proceeds from the issue
were initially used to pay down Provident's bank debt and throughout
2004 have been used to finance the company's 2004 capital budget.

On June 1, 2004 the Trust issued 13.4 million units (at an ascribed
value of $152.9) and a further 12.8 million units (at an ascribed value
of $145.7 million) as part of the consideration to acquire the
outstanding shares of Olympia Energy Inc. and Viracocha Energy Inc.
respectively. 1.325 million exchangeable shares of Provident Energy Ltd.
were issued pursuant to each transaction as well for a total of 2.65
million additional exchangeable shares. The Exchangeable Shares will be
automatically exchanged for Trust Units on January 15, 2006, subject to
extension at the option of the Offeror. The exchange ratio for these
shares is calculated with reference to the distributions.

On July 6, 2004 the Trust issued 13.1 million units at $10.40 per unit
for proceeds of $136.2 million ($129.4 million net of issue costs)
pursuant to a June 17, 2004 public offering. Proceeds from the issue
applied to pay down the bridge financing used in the BreitBurn Energy
LLC acquisition.

On October 4, 2004 the Trust closed a bought deal issuing 11.48 million
units at $10.95 per unit for net proceeds (after underwriters' fees) of
$119.4 million. Proceeds were used to fund the Orcutt acquisition ($58.5
million) and to repay bank debt.

At December 31, 2004 management and directors held approximately 1.6
percent of the outstanding units and exchangeable shares.

Non-controlling interest

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.



Year ended December 31,
---------------------------------------------------------------------
($ 000s) 2004
---------------------------------------------------------------------
Opening non-controlling interest, June 15, 2004 $ 13,690
Non-controlling interest in earnings for the period 923
Distributions to non-controlling interest holders (964)
---------------------------------------------------------------------
Closing non-controlling interest, December 31, 2004 $ 13,649
---------------------------------------------------------------------


Additional investments by Provident in BreitBurn Energy LP have reduced
the non-controlling interest percentage at December 31, 2004 to
approximately 5.8 percent.



Capital expenditures and funding

Year ended December 31,
---------------------------------------------------------------------
($ 000s) 2004 2003
---------------------------------------------------------------------
Capital Expenditures and Funding
Capital Expenditures
Capital expenditures and reclamation
fund contributions $ (79,165) $ (34,120)
Property acquisitions (72,745)
Corporate acquisitions (173,657) (299,002)
Property dispositions 10,717 9,947
----------------------------
Net capital expenditures $ (314,850) $ (323,175)
----------------------------
----------------------------

Funded By

Cash flow net of declared distributions to
unitholders and non-controlling interest $ 19,654 $ (1,247)
Proceeds of bridge financing 158,184 -
Repayment of bridge financing (158,184) -
Issue of convertible debentures,
net of cost 48,000 71,800
Issue of trust units, net of cost;
excluding DRIP 301,110 192,854
DRIP proceeds 19,866 27,408
Reimbursement for leasehold improvements - 1,437
Change in working capital 3,307 (18,377)
Increase (decrease) in bank debt (77,087) 49,300
----------------------------
$ 314,850 $ 323,175
----------------------------
----------------------------

Note: The above table does not include the amount attributed to
acquisitions where consideration was paid by issuing units of the
trust or non-cash consideration received for dispositions.


Capital expenditures were funded by a combination of DRIP proceeds,
proceeds received on non-core property dispositions, cash flow, equity,
exchangeable shares and debt. Provident's strategy is to fund
acquisitions by accessing the capital markets and to fund capital
expenditures through DRIP and other equity if needed.

Net asset value

Provident's net asset value (NAV)as at December 31, 2004, is summarized
in the table below. The NAV is calculated on a fully diluted basis,
which includes exchangeable shares and unit options, and is presented at
eight percent and ten percent discounted cash flow cases. The pricing
used at both December 31, 2004 and December 31, 2003 is derived from the
McDaniel's report.



($000s except per unit data) PV 8% PV 10%
---------------------------------------------------------------------
Net Asset Value:
Present value of proved plus probable oil
and natural gas reserves(1) $ 1,248,161 $ 1,134,555
Midstream assets 451,869 387,360
Add:
Land(3)(4) 71,652 71,652
Proceeds from Options 57,252 57,252
Cash Reserved for Future Reclamation 1,454 1,454
Investments 3,000 3,000
Less:
Financial Hedging Losses (22,498) (22,295)
Long Term Debt (432,206) (432,206)
Working (Deficiency) Capital (38,677) (38,677)
Minority Interest (13,649) (13,649)

--------------------------
Consolidated Provident Net Asset Value $ 1,326,358 $ 1,148,446
--------------------------
--------------------------

Consolidated Provident Net Asset Value
per Unit $ 8.78 $ 7.61
--------------------------
--------------------------

2003 comparatives
Consolidated Provident Net Asset Value
per Unit $ 6.41 $ 5.55
--------------------------
--------------------------

(1) Evaluated by McDaniel's, NSA and CGA; pricing is McDaniel
pricing effective December 31, 2004
(2) The Midstream assets represent a discounted cash flow stream
(EBITDA less maintenance capital) of $39.7 million for 25 years
(3) Canadian land holdings evaluated by Seaton Jordan & Associates
Ltd. effective December 31, 2004
(4) U.S. land holdings are included at the market value assigned at
the date of acquisitions


Asset retirement obligation

Year ended December 31,
---------------------------------------------------------------------
($ 000s) 2004 2003
---------------------------------------------------------------------
Carrying amount, beginning of period $ 33,182 $ 32,645
Oil and gas corporate acquisitions 12,171 -
Change in estimate (2,429) -
Increase in liabilities incurred during the
period 166 519
Settlement of liabilities during the period (4,971) (2,153)
Accretion expense 2,387 2,171
----------------------
Carrying amount, end of period $ 40,506 $ 33,182
----------------------


The asset retirement obligation (ARO) increased by $7.3 million to $40.5
million during 2004.

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 $130.4 million. Payments to settle oil and gas asset
retirement obligations occur over the operating lives of the assets
estimated to be from two to 20 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 includes expenses or recoveries
associated with Provident's unit option plan. Provident accounts for the
unit option plan using the fair value of the option, at the time of
issue. Compensation expense associated with the options is deferred and
recognized in earnings over the vesting period of the options. Provident
recorded an expense of $1.8 million for the year ended December 31, 2004
(2003 -$1.3 million).

Canadian OGP business unit (COGP)

Crude oil price

The following prices are net of transportation expense.



COGP Year ended December 31,
---------------------------------------------------------------------
($per bbl) 2004 2003 % Change
---------------------------------------------------------------------
Oil per barrel
WTI (US$) $ 41.43 $ 31.02 34
Exchange rate (from US$ to Cdn$) $ 1.30 $ 1.41 (8)
WTI expressed in Cdn$ $ 53.86 $ 43.74 23

COGP realized crude oil and natural
gas liquids price before hedging
(Cdn$) $ 36.81 $ 30.77 20

COGP realized light/medium oil price
before hedging (Cdn$) $ 42.79 $ 36.02 19

COGP realized heavy oil price before
hedging (Cdn$) $ 28.72 $ 24.74 16

COGP realized natural gas liquids
price before hedging (Cdn$) $ 40.61 $ 35.87 13
-------------------------------


For the year ended December 31, 2004 Provident's pre-hedged oil and
natural gas liquids price increased by 20 percent to average $36.81
compared to $30.77 in 2003. This reflects a 34 percent increase in the
U.S. dollar denominated WTI partly offset by the increase in value of
the Canadian dollar versus the U.S. dollar, and significantly increased
differentials between WTI and realized heavy oil prices.

Natural gas price

The following prices are net of transportation expense.



COGP Year ended December 31,
---------------------------------------------------------------------
($per mcf) 2004 2003
---------------------------------------------------------------------

AECO monthly index (Cdn$) per mcf $ 6.79 $ 6.69
Corporate natural gas price per mcf
before hedging (Cdn$) $ 6.59 $ 6.63

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


For 2004 the per mcf pre-hedged natural gas price of $6.59 received by
Provident was comparable to the $6.63 per mcf received in 2003.



Production

Year ended December 31,
---------------------------------------------------------------------
COGP 2004 2003 % Change
---------------------------------------------------------------------
Daily production
Crude oil - Light/Medium (bpd) 7,995 6,812 17
- Heavy (bpd) 6,608 6,902 (4)
Natural gas liquids (bpd) 1,482 1,167 27
Natural gas (mcfd) 76,174 74,596 2
Oil equivalent (boed) (1) 28,781 27,314 5
---------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas
to oil on a 6:1 basis.
---------------------------------------------------------------------


For 2004, Provident's COGP production averaged 28,781 boed, consistent
with 2003. Excluding the volumes associated with the acquisitions,
Provident's previous production base decreased due primarily to natural
production declines and dispositions offset by volumes added through
development activities. Additions to production through internal capital
replaced approximately 40 percent of proved plus probable reserves.
Provident's 2004 development activities were hampered by poor weather
conditions in the first, second, and fourth quarters, which delayed
overall development activities. Production volumes added from the
Olympia and Viracocha acquisitions also contributed to the replacement
of production declines.

Provident's production of approximately 31,500 boed as at December 31,
2004 is approximately 20 percent above the 2003 exit production level of
26,190 boed. Production as at December 31, 2004 is weighted 44 percent
natural gas, 35 percent medium/light crude oil and natural gas liquids
and 21 percent conventional heavy oil. Provident does not have any
single property providing greater than 10 percent of daily production.



Revenue and royalties

COGP Year ended December 31,
---------------------------------------------------------------------
($ 000s except per boe data) 2004 2003 % Change
---------------------------------------------------------------------
Oil
Revenue $ 194,366 $ 151,874 28
Realized loss on non-hedging
derivative instruments (54,997) (23,892) 130
Royalties (net of ARTC) (38,885) (29,156) 33
--------------------------------
Net revenue $ 100,484 $ 98,826 2
--------------------------------
--------------------------------
Net revenue (per barrel) $ 18.80 $ 19.74 (5)
Royalties as a percentage of revenue 20.0 19.2

Natural gas
Revenue $ 183,704 $ 180,590 2
Realized loss on non-hedging
derivative instruments (10,369) (25,042) (59)
Royalties (net of ARTC) (40,813) (39,190) 4
--------------------------------
Net revenue $ 132,522 $ 116,358 14
--------------------------------
--------------------------------
Net revenue (per mcf) $ 4.75 $ 4.24 12
Royalties as a percentage of revenue 22.2 21.7

Natural gas liquids
Revenue $ 22,024 $ 15,282 44
Royalties (5,492) (4,523) 21
--------------------------------
Net revenue $ 16,532 $ 10,759 10,759
--------------------------------
--------------------------------
Net revenue (per barrel) $ 30.48 $ 25.25 21
Royalties as a percentage of revenue 24.9 29.6

Total
Revenue $ 400,094 $ 347,746 15
Realized loss on non-hedging
derivative instruments (65,366) (48,934) 34
Royalties (net of ARTC) (85,190) (72,869) 17
--------------------------------
Net revenue $ 249,538 $ 225,943 10
--------------------------------
--------------------------------
Net revenue per boe $ 23.69 $ 22.58 5
Royalties as a percentage of revenue 21.3 21.0
---------------------------------------------------------------------
Note: the above figures are presented net of transportation expenses
and service revenue.
---------------------------------------------------------------------


Total COGP revenue for the 2004 was $249.5 million, an increase of 10
percent from $171.1 million for 2003. The increased revenue reflects a
five percent increase in production volumes and increased crude oil
prices partly offset by higher cash hedging losses. Average royalty
rates remained comparable in total year over year.



Production expenses

COGP Year ended December 31,
---------------------------------------------------------------------
(000s, except per boe data) 2004 2003 % change
---------------------------------------------------------------------
Production expenses $ 90,330 $ 76,396 18
Production expenses (per boe) $ 8.58 $ 7.66 12
---------------------------------------------------------------------


In 2004 COGP operating costs increased 18 percent to $90.3 million from
$76.4 million in 2003. This increase reflects a five percent gain in
production volumes, an increase in optimization activities and higher
costs for field services. On a per boe basis costs increased to $8.58
per boe or 12 percent above the $7.66 per boe recorded in 2003. The
increase in per boe costs includes an increase in power, processing,
servicing and workover activity driven largely by the higher commodity
price environment. Operating costs for 2005 in a high commodity price
environment with increased levels of activity are forecast to average
$8.75 per boe to $9.25 per boe.

General and administrative

The following table does not incorporate the COGP portion of non-cash
general and administrative charges associated with Provident's unit
option plan. A non-cash expense of $0.9 million was recorded in 2004.



COGP Year ended December 31,
---------------------------------------------------------------------
($ 000s, except per boe data) 2004 2003 % change
---------------------------------------------------------------------
Cash general and administrative $ 16,439 $ 14,289 15
Cash general and administrative
per boe $ 1.56 $ 1.43 9
---------------------------------------------------------------------


In 2004 COGP general and administrative expenses increased 15 percent to
$16.4 million compared to $14.3 million in 2003. The increase in general
and administrative expenses reflects additional costs associated with an
increase in staff, rent, insurance and compliance and reporting costs.
The Canadian operations are capable of absorbing additional production,
particularly in existing core areas, with little impact on general and
administrative expenses. For 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.

Operating netback

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



COGP Year ended December 31,
---------------------------------------------------------------------
($per boe) 2004 2003 % change
---------------------------------------------------------------------
Netback per boe
Gross production revenue $ 37.99 $ 35.07 8

Royalties (net of ARTC) (8.08) (7.31) 11
Operating costs (8.58) (7.66) 12
---------------------------------------------------------------------
Field operating netback 21.33 20.10 6

Realized loss on cash hedging (6.18) (4.91) 26
---------------------------------------------------------------------
Operating netback after hedging $ 15.15 $ 15.19 -
---------------------------------------------------------------------


For the year ended December 31, 2004 the field operating netback
increased six percent to $21.33 per boe. Higher commodity prices more
than offset increases in royalties and operating costs. Netbacks after
hedging cost were lower than the comparable 2003 period at $15.15 per
boe versus $15.19 per boe. The decrease in the netback is due to higher
field revenues being more than offset by higher royalties, operating
costs and opportunity costs on hedging.



Depletion, depreciation and accretion (DD&A)

COGP Year ended December 31,
---------------------------------------------------------------------
($000s, except per boe data) 2004 2003
---------------------------------------------------------------------

DD&A $ 160,271 $ 136,066

DD&A per boe $ 15.21 $ 13.65
---------------------------------------------------------------------


The COGP DD&A rate increased to $15.21 per boe compared to $13.65 per
boe for 2003. The increase is mainly due to the cost of acquiring proved
reserves in 2004 in western Canada in an environment where reserve costs
escalated with higher commodity prices. The result was proved reserves
in 2004 were acquired at a higher cost per boe than Provident's
historical asset base.

In 2004 DD&A also includes accretion expense associated with asset
retirement obligation of $2.4 million versus $2.2 million in 2003.



Capital expenditures

COGP Year ended December 31,
---------------------------------------------------------------------
($000s) 2004 2003
---------------------------------------------------------------------

Lloydminster $ 10,215 $ 12,200
West central and southern Alberta 24,299 11,936
Southeast and southwest Saskatchewan 25,810 3,854
Office and other 1,130 3,638
---------------------------------------------------------------------
Total additions $ 61,454 $ 31,628
---------------------------------------------------------------------

Property acquisitions $ 5,088 $ -

Dispositions (1) $ (13,717) $ (9,947)
----------------------------------------------------------------------
(1) Includes $3.0 million of non-cash proceeds on a disposition - see
note 13.


In 2004, Provident's COGP business unit spent $10.2 million in the
Lloydminster core area on drilling, recompletions, equipping and seismic
activity. In the west central area $9.5 million was spent largely on
non-operated capital and in the southern Alberta core area $14.8 million
went toward drilling activities, recompletions and facility upgrades.
Provident spent $25.8 million in the southeast and southwest
Saskatchewan core areas on acquiring mineral rights for future
development, drilling for shallow gas and recompletions. Office and
other accounted for $1.1 million of capital.

In 2004 asset dispositions of non-core assets totaled $13.7 million
compared to $9.9 million in 2003.

For the year ended December 31, 2003, Provident incurred capital
expenditures of $31.6 million, of which $12.2 million was spent in the
Lloydminster core area drilling 28 net heavy oil wells, as well as on
land and seismic. In west central and southern Alberta $11.9 million was
spent on operated and non-operated drilling projects as well as on
facility and optimization projects and land purchases. Southeast and
southwest Saskatchewan capital expenditures of $3.9 million were
directed at drilling, recompletions and facility projects. The remaining
$3.6 million was spent primarily on Provident's head office move and
leasehold improvements.

In 2003 $9.9 million of assets were disposed of that primarily related
to the sale of acreage with a risk profile that did not meet internal
criteria.

Provident's capital expenditures are partly funded through the Premium
Distribution, Distribution Reinvestment and Optional Unit Purchase Plan
(DRIP). The DRIP program allows investors to reinvest distributions into
trust units. Provident directed proceeds from the DRIP program of $19.9
million in 2004 (2003 - $27.4 million), along with the proceeds from
asset dispositions, towards the capital expenditure budget.

The 2005 capital budget approved by the Board of Director's for COGP is
$68.8 million.

United States OGP business unit

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. A majority
stake in BreitBurn was purchased June 15, 2004.



Crude oil price


USOGP Year ended December 31,
---------------------------------------------------------------------
($per bbl) 2004
---------------------------------------------------------------------
Oil per barrel
WTI (US$) $ 41.43
Exchange rate (from US$ to Cdn$) $ 1.30
WTI expressed in Cdn$ $ 53.86
USOGP realized crude oil and natural gas liquids price
before hedging (Cdn$) $ 53.24
USOGP realized light/medium oil price before hedging
(Cdn$) $ 52.42
USOGP realized natural gas liquids price before hedging
(Cdn$) $ 49.33
---------------------------------------------------------------------


The USOGP oil production is primarily light, sweet crude, which attracts
prices with a very small ($0.60 per barrel) differential to benchmark
prices.



Production

For the period of
June 15, 2004 to
December 31,
---------------------------------------------------------------------
USOGP 2004
---------------------------------------------------------------------
Daily production
Crude oil - Light/Medium (bpd) 3,954
Natural gas liquids (bpd) 23
Natural gas (mcfd) 1,559
Oil equivalent (boed)(1) 4,237
---------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to
oil on a 6:1 basis.
---------------------------------------------------------------------


The daily production figures in this section are for the June to
December period. The effect of the production from U.S. operations on
consolidated daily production is on an annual basis.

Excluding the Orcutt acquisition, USOGP production increased by
approximately four percent or 158 boe per day in the period June 15 to
December 31, 2004. The increase in base production is primarily
attributable to drilling and optimization programs at West Pico and
Santa Fe Springs offset by natural production declines. The Orcutt
acquisition added 1,425 boe per day for the period October 4, to
December 31, 2004. The exit production rate for 2004 was approximately
5,200 boe per day.



Revenue and royalties

The following table outlines USOGP revenue and royalties by product
line. The table excludes revenues earned from operating certain
properties (of $0.6 million year to date) on behalf of third parties.

Year ended
USOGP December 31,
---------------------------------------------------------------------
($ 000s, except per boe amounts) 2004
---------------------------------------------------------------------
Oil
Revenue $ 41,983
Realized loss on non-hedging derivative instrument (425)
Royalties (4,009)
---------------------------------------------------------------------
Net revenue $ 37,549
---------------------------------------------------------------------
Net revenue (per barrel) $ 47.72
Royalties as a percentage of revenue 9.5

Natural gas
Revenue $ 2,482
Realized loss on non-hedging derivative instrument -
Royalties -
---------------------------------------------------------------------
Net revenue $ 2,482
---------------------------------------------------------------------
Net revenue (per mcf) $ 8.00
Royalties as a percentage of revenue 0

Natural gas liquids
Revenue $ 223
Royalties -
---------------------------------------------------------------------
Net revenue $ 223
---------------------------------------------------------------------
Net revenue (per barrel) $ 49.28
Royalties as a percentage of revenue 0

Total
Revenue $ 44,688
Realized loss on non-hedging derivative instrument (425)
Royalties (4,009)
---------------------------------------------------------------------
Net revenue $ 40,254
---------------------------------------------------------------------
Net revenue per boe $ 47.74
Royalties as a percentage of revenue 9.0
---------------------------------------------------------------------

Note: the above figures are presented net of transportation expenses.
---------------------------------------------------------------------


Production expenses

Year ended
USOGP December 31,
---------------------------------------------------------------------
($ 000s, except per boe amounts) 2004
---------------------------------------------------------------------
Production expenses $ 13,173
Production expenses (per boe) $ 15.62
---------------------------------------------------------------------


USOGP Production expenses are higher than expected in the period June 15
to December 31, 2004 due to less than expected incremental production
from certain drilling activities as well as continuing increases in the
cost of goods and services due to the high commodity price environment.
BreitBurn also returned some higher operating cost wells to production
due to the current high commodity price environment. Operating costs for
2005 are expected to average between $13.00 and $13.50, at a
USD$1.00=CAD$1.25 exchange rate, primarily due to projected increases in
production.

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 and an internal management charge. A year to
date non-cash expense for the unit appreciation rights plan and the
internal management charge of $0.8 million and $0.7 million respectively
has been recorded in 2004.



Year ended
USOGP December 31,
---------------------------------------------------------------------
($ 000s, except per boe amounts) 2004
---------------------------------------------------------------------
Cash general and administrative $ 4,113
Cash general and administrative per boe $ 4.85
---------------------------------------------------------------------


General and administrative expenses in the USOGP unit are expected to
increase slightly in absolute terms with the Nautilus acquisition (which
was completed March 2, 2005), but to slightly decrease on a per unit
(boe) basis. The U.S. operations are capable of absorbing additional
production, particularly in core areas, with minor increases in general
and administrative expenses.



Operating netback

Year ended
USOGP December 31,
---------------------------------------------------------------------
($ per boe) 2004
---------------------------------------------------------------------
Netback per boe
Gross production revenue $ 52.92

Royalties (4.76)
Operating costs (15.62)
-------------
Field operating netback 32.54

Cash hedging (0.79)
-------------
Operating netback after hedging $ 31.75
---------------------------------------------------------------------


Despite higher than expected operating costs, USOGP operating netbacks
remained strong throughout 2004 due to high commodity prices.



Income taxes and cash taxes

Year ended
USOGP December 31,
---------------------------------------------------------------------
($ 000s) 2004
---------------------------------------------------------------------

Current and withholding taxes $ 1,201

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


Current and withholding taxes include current U.S. federal and state
income taxes as well as accrued or paid U.S. withholding taxes on
distributions that have been or will be made from BreitBurn Energy LP to
Provident.



Depletion, depreciation and accretion (DD&A)


Year ended
USOGP December 31,
---------------------------------------------------------------------
($ 000s, except per boe amounts) 2004
---------------------------------------------------------------------

DD&A $ 7,402
DD&A per boe $ 8.78

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


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

Capital expenditures

USOGP capital expenditures for the quarter ended December 31, 2004
totaled $79.3 million. This includes $58.5 million for the Orcutt
property acquisition, $3.1 million to increase BreitBurn's working
interest in certain wells at West Pico and Sawtelle, $7.3 million on
drilling, optimization and facility upgrades at West Pico, $5.0 million
on drilling, optimization and facility upgrades at Santa Fe Springs and
$5.4 million on facility upgrades and optimization programs at other
USOGP properties. Optimization capital was partially focused at
returning previously uneconomic wells to production due to the high
commodity price environment.

Oil and natural gas reserves

In order to provide clarity in Provident's reserve reporting, the
reserves are illustrated by country and on a consolidated basis. The
Canadian and U.S evaluation reports used the McDaniel & Associates
(McDaniel) price forecast at January 1, 2005 and are prepared in
accordance with disclosure standards as mandated by the Canadian
Securities Administrators' National Instrument 51-101 (NI 51-101)
Standards of Disclosure for Oil and Gas Activities. NI-51-101
establishes prescribed disclosures regarding oil and natural gas
information and provides enhanced corporate governance measures by
mandating the involvement of independent reserves evaluators in the
preparation of reserves data and assigning responsibility for the
content of reserves data directly to management and the board of
directors.

Under NI-51-101, proved reserves are defined as having a high degree of
certainty to be recoverable and probable reserves are defined as those
reserves that are less certain to be recovered than proved reserves. The
targeted levels of certainty, in aggregate, are at least 90 percent
probability that the quantities actually recovered will equal or exceed
the estimated proved reserves and at least a 50 percent probability that
the quantities recovered will equal or exceed the sum of the estimated
proved plus probable reserves. The most significant aspect of reporting
under NI-51-101 standards is the definition of proved plus probable as a
"best estimate" of future recoverable reserves.

Provident consolidated oil and natural gas reserves

Provident had a very successful year with respect to reserves addition
activities and the drive to continually support the sustainability of
the trust. The Trust's reserves more than doubled after production with
proved producing reserves growing from 35,466 Mboe to 73,715 Mboe, total
proved growing from 41,868 Mboe to 99,627 Mboe, and proved plus probable
growing from 54,894 Mboe to 130,800 Mboe. Reserve life indices increased
as well largely due to the acquisition of low decline, long life
reserves in the U.S. Acquisitions accounted for most of the growth in
reserves volumes however it is noteworthy that internal development
activities in Western Canada were successful in replacing approximately
36 percent of total production. NI 51-101 requires that acquisitions be
reported as per the evaluation completed at the time of the year-end
filing. To comply with this requirement all 2004 acquisitions are
summarized herein as per the McDaniel, Cawley, Gillespie and Associates,
Inc. (CGA) and Netherland, Sewell and Associates, Inc. (NSA) December
31, 2004 evaluations with actual production added back to develop the
effective volumes acquired at the time of acquisition. These volumes may
be different than those presented in press releases at the time of
acquisition due to different effective dates, impacting production as
well as technical and economic revisions. Additional reserves detail can
be found in the Trust's Annual Information Form.

Canadian oil and natural gas reserves

Provident's Canadian oil and natural gas reserves as of December 31,
2004 were evaluated or reviewed by McDaniel. McDaniel evaluated the
properties that comprise approximately 81 percent of the value of the
Canadian oil and gas reserves. The remaining 19 percent of value was
evaluated by qualified Provident staff and ultimately reviewed by
McDaniel. In 2003 a similar approach was taken with McDaniel evaluating
approximately 75 percent of Provident's Canadian properties.

Total proved reserves increased by 49 percent and proved plus probable
reserves increased by 44 percent, before accounting for production, and
24 percent and 25 percent respectively after production. Acquisitions
were the major factor accounting for 77 percent of the total proved and
83 percent of the proved plus probable increases before production.
Additions due to drilling made a significant contribution with total
proved additions replacing 29 percent of production and proved plus
probable additions replacing 39 percent of Canadian production.

Revisions, excluding economic factors, accounted for a three percent
increase in total proved reserves and minus one percent for proved plus
probable reserves. Higher commodity prices resulted in positive
revisions due to economic factors of approximately 2 percent. Production
in 2004 totaled 10,534 Mboe and along with acquisitions and
divestitures, additions and revisions, resulted in a proved plus
probable reserve closing balance at December 31, 2004 of 68,672 Mboe
compared to 54,894 Mboe on December 31, 2003.

United States

Provident's U. S. oil and natural gas reserves as of December 31, 2004
were evaluated by NSA and CGA. NSA evaluated properties that comprise
approximately 90 percent of the value of the U. S. reserves with CGA
evaluating the remainder. The U. S. reserves evaluations comply with NI
51-101 and both companies are qualified to evaluate reserves in
accordance with the Canadian reporting requirements.

The increase in commodity prices between the acquisition dates and
year-end, when applied to the shallow decline rates of the United States
reserves, resulted in significant positive revisions due to economic
factors. These factors resulted in a 15 percent increase in the proved
developed producing and total proved reserves, and a 16 percent increase
in proved plus probable reserves over the assignments at the time of
purchase.

Provident consolidated oil and natural gas reserves

The following reconciliation summarizes Provident's consolidated reserve
activity for the year ended December 31, 2004, on the basis of working
interest, and net interest after royalties.



Provident consolidated(d)
Proved developed producing

Light &
Medium Crude Heavy Total
Oil Crude Oil Crude Oil
Company Share (WI +RI) (a)(c) Mbbl Mbbl Mbbl
---------------------------------------------------------------------
Balance at December 31, 2003 11,195 3,937 15,132
Production (3,598) (2,482) (6,080)
Acquisition 33,999 2,146 36,145
Divestiture (148) (1) (149)
Exploration Discoveries 0 0 0
Drilling Extensions 262 692 954
Recompletion 197 73 270
Transfer 0 186 186
Economic Factors 491 223 714
Technical Revisions 1,044 396 1,440

---------------------------------------------------------------------
Balance at December 31, 2004 43,442 5,169 48,611
---------------------------------------------------------------------

---------------------------------------------------------------------
(WI) Share (b)
Balance at December 31, 2004 43,393 5,158 48,551
---------------------------------------------------------------------
---------------------------------------------------------------------


Gas NGL BOE
Company Share (WI +RI) (a)(c) MMcf Mbbl Mboe
---------------------------------------------------------------------
Balance at December 31, 2003 109,019 2,164 35,466
Production (28,435) (542) (11,361)
Acquisition 44,517 1,208 44,772
Divestiture (910) (21) (321)
Exploration Discoveries 763 22 149
Drilling Extensions 2,285 36 1,370
Recompletion 2,580 9 709
Transfer 164 0 213
Economic Factors 1,031 10 896
Technical Revisions 1,929 60 1,822

---------------------------------------------------------------------
Balance at December 31, 2004 132,943 2,947 73,715
---------------------------------------------------------------------

---------------------------------------------------------------------
(WI) Share (b)
Balance at December 31, 2004 130,972 2,902 73,281
---------------------------------------------------------------------
---------------------------------------------------------------------


Provident consolidated (d)
Total proved

Light &
Medium Crude Heavy Total
Oil Crude Oil Crude Oil
Company Share (WI +RI) (a)(c) Mbbl Mbbl Mbbl
---------------------------------------------------------------------
Balance at December 31, 2003 11,773 7,473 19,246
Production (3,598) (2,481) (6,080)
Acquisition 46,286 4,669 50,956
Divestiture (148) (153) (301)
Exploration Discoveries 0 0 0
Drilling Extensions 262 835 1,097
Recompletion 197 73 270
Transfer 0 3 3
Economic Factors 492 265 757
Technical Revisions 1,062 (38) 1,024

---------------------------------------------------------------------
Balance at December 31, 2004 56,324 10,646 66,971
---------------------------------------------------------------------

---------------------------------------------------------------------
(WI) Share (b)
Balance at December 31, 2004 56,252 10,634 66,887
---------------------------------------------------------------------
---------------------------------------------------------------------


Gas NGL BOE
Company Share (WI +RI) (a)(c) MMcf Mbbl Mboe
---------------------------------------------------------------------
Balance at December 31, 2003 122,093 2,273 41,868
Production (28,435) (542) (11,361)
Acquisition 67,782 1,981 64,234
Divestiture (910) (21) (473)
Exploration Discoveries 763 22 149
Drilling Extensions 6,133 36 2,156
Recompletion 2,972 9 774
Transfer 0 0 3
Economic Factors 1,030 10 938
Technical Revisions 1,272 103 1,339

---------------------------------------------------------------------
Balance at December 31, 2004 172,700 3,873 99,627
---------------------------------------------------------------------

---------------------------------------------------------------------
(WI) Share (b)
Balance at December 31, 2004 170,318 3,824 99,097
---------------------------------------------------------------------
---------------------------------------------------------------------


Provident consolidated (d)
Total proved plus probable

Light &
Medium Crude Heavy Total
Oil Crude Oil Crude Oil
Company Share (WI +RI) (a)(c) Mbbl Mbbl Mbbl
---------------------------------------------------------------------
Balance at December 31, 2003 14,971 11,875 26,846
Production (3,598) (2,482) (6,080)
Acquisition 57,233 8,164 65,397
Divestiture (167) (538) (704)
Exploration Discoveries 0 0 0
Drilling Extensions 321 1,074 1,395
Recompletion 202 92 294
Transfer 0 8 8
Economic Factors 679 410 1,089
Technical Revisions 488 (724) (237)

---------------------------------------------------------------------
Balance at December 31, 2004 70,128 17,880 88,007
---------------------------------------------------------------------

---------------------------------------------------------------------
(WI) Share (b)
Balance at December 31, 2004 70,043 17,865 87,908
---------------------------------------------------------------------
---------------------------------------------------------------------


Gas NGL BOE
Company Share (WI +RI) (a)(c) MMcf Mbbl Mboe
---------------------------------------------------------------------
Balance at December 31, 2003 151,392 2,816 54,894
Production (28,435) (542) (11,361)
Acquisition 89,034 2,832 83,067
Divestiture (1,013) (24) (897)
Exploration Discoveries 916 27 179
Drilling Extensions 8,512 57 2,870
Recompletion 4,522 11 1,059
Transfer 0 0 8
Economic Factors 1,130 10 1,287
Technical Revisions (804) 64 (307)

---------------------------------------------------------------------
Balance at December 31, 2004 225,252 5,251 130,800
---------------------------------------------------------------------

---------------------------------------------------------------------
(WI) Share (b)
Balance at December 31, 2004 222,343 5,189 130,155
---------------------------------------------------------------------
---------------------------------------------------------------------

(a) Company share includes working interest (WI) and royalty
interests (RI).
(b) WI share includes the Companies working interests only, and
excludes volumes associated with royalties paid to others.
(c) Tables may not add due to rounding.
(d) Reserves and values reported are based on 100 percent of the
interests of Breitburn L.P. in the U.S. properties as at
December 31, 2004. Provident indirectly holds approximately
94.2 percent of the outstanding partnership interests of
Breitburn L.P. with the remaining approximately 5.8 percent
of the partnership interests held by Breitburn's co-founders
and co-chief executive officers.


Provident's Consolidated oil and natural gas reserves and present value
of estimated future cash flows based on forecast (escalated) price
assumptions are summarized below.




Provident consolidated reserves summary(a)(b)
Using McDaniel January 1, 2004 Forecast Pricing

Gross Reserves(c)
---------------------------------------------------------------------
Light & Heavy
Medium Crude Total
Crude Oil Oil Oil NGLs Gas Boe
--------- ----- ------ ------ -------- --------
(mbbls) (mbbls) (mmcf) (mboe)
Proved Reserves

Producing 43,393 5,158 48,551 2,902 130,972 73,281

Non-Producing 4,229 690 4,919 185 21,421 8,674

Undeveloped 8,630 4,787 13,417 738 17,924 17,142

Total Proved 56,252 10,634 66,887 3,824 170,318 99,097

Probable 13,791 7,231 21,022 1,365 52,026 31,058

TOTAL Proved
plus Probable 70,043 17,865 87,908 5,189 222,343 130,155




Net Reserves(d)
---------------------------------------------------------------------
Light & Heavy
Medium Crude Total
Crude Oil Oil Oil NGLs Gas Boe
--------- ----- ------ ------ -------- --------
(mbbls) (mbbls) (mmcf) (mboe)
Proved Reserves

Producing 39,053 4,532 43,585 2,258 109,913 64,162

Non-Producing 3,870 580 4,450 147 17,434 7,502

Undeveloped 7,153 4,333 11,486 603 15,377 14,651

Total 50,075 9,445 59,520 3,008 142,724 86,315

Probable 12,049 6,541 18,599 1,078 43,826 26,972

TOTAL Proved
plus Probable 62,124 15,986 78,110 4,086 186,550 113,288

(a) Tables may not add due to rounding.
(b) Reserves and values reported are based on 100 percent of the
interests of Breitburn L.P. in the U.S. properties as at
December 31, 2004. Provident indirectly holds approximately 94.2
percent of the outstanding partnership interests of Breitburn
L.P. with the remaining approximately 5.8 percent of the
partnership interests held by Breitburn's co-founders and
co-chief executive officers.
(c) Gross Reserves are Provident's working interest (operating or
non-operating) share before deducting of royalties and without
including any royalty interests of Provident.
(d) Net Reserves are Provident's working interest (operating or
non-operating) share after deduction of royalty obligations, plus
Provident's royalty interests in reserves.


Provident consolidated present value of reserves (a)(b)(c)

Present Worth Value Before Tax Discounted at
--------------------------------------------------------
0% 8% 10% 15% 20%
---------- ---------- ---------- ---------- ------------
($ 000's)
Proved
Reserves
Producing $1,123,630 $ 828,534 $ 777,562 $ 685,205 $617,667
Non-
Producing 125,043 72,478 65,379 52,380 43,552
Undeveloped 300,677 159,591 135,085 101,519 79,071
---------- ---------- ---------- ---------- ------------
Total Proved 1,549,350 1,060,603 978,026 839,104 740,290
Probable 607,083 308,538 266,933 203,441 162,731
---------- ---------- ---------- ---------- ------------
TOTAL
Proved plus
Probable $2,156,432 $1,369,141 $1,244,959 $1,042,545 $903,022
---------- ---------- ---------- ---------- ------------
---------- ---------- ---------- ---------- ------------


Present Worth Value After Tax(d) Discounted at
--------------------------------------------------------
0% 8% 10% 15% 20%
---------- ---------- ---------- ---------- ------------
($ 000's)
Proved
Reserves
Producing $1,090,901 $ 802,947 $ 752,816 $663,111 $597,558
Non-
Producing 76,391 42,293 37,569 29,694 24,416
Undeveloped 257,912 136,346 114,587 86,902 68,593
---------- ---------- ---------- ---------- ------------
Total Proved 1,425,203 981,587 904,973 779,707 690,567
Probable 527,922 266,574 229,582 175,646 141,248
---------- ---------- ---------- ---------- ------------
TOTAL
Proved plus
Probable $1,953,124 $1,248,161 $1,134,555 $955,353 $831,816
---------- ---------- ---------- ---------- ------------
---------- ---------- ---------- ---------- ------------

(a) Present values include the effects of hedging
(b) Tables may not add due to rounding
(c) Reserves and values reported are based on 100 percent of the
interests of Breitburn L.P. in the U.S. properties as at
December 31, 2004. Provident indirectly holds approximately 94.2
percent of the outstanding partnership interests of Breitburn
L.P. with the remaining approximately 5.8 percent of the
partnership interests held by Breitburn's co-founders and
co-chief executive officers.
(d) After tax values include U.S. State and Federal Taxes as well as
with holding tax on funds that flow back to Provident Energy Ltd.
in Canada.


Provident's Canadian oil and natural gas reserves and present value of
estimated future cash flows based on forecast (escalated) price
assumptions are summarized below.



Canada reserves summary(a)

(a) Tables may not add due to rounding.

Gross Reserves
---------------------------------------------------------------------
Light & Heavy
Medium Crude Natural
Crude Oil Oil Oil NGLs Gas Boe
--------- ----- ------ ------ -------- --------
(mbbls) (mbbls) (mmcf) (mboe)
Proved Reserves
Producing 15,258 3,509 18,766 2,828 123,228 42,132
Non-Producing 498 683 1,181 185 20,550 4,790
Undeveloped 255 2,817 3,072 131 7,264 4,413
--------- ----- ------ ------ -------- --------
Total Proved 16,011 7,008 23,019 3,144 151,042 51,336
Probable 4,021 4,315 8,336 994 44,163 16,690
--------- ----- ------ ------ -------- --------

TOTAL Proved
plus Probable 20,032 11,323 31,355 4,137 195,204 68,026
--------- ----- ------ ------ -------- --------
--------- ----- ------ ------ -------- --------



Net Reserves
---------------------------------------------------------------------
Light & Heavy
Medium Crude Natural
Crude Oil Oil Oil NGLs Gas Boe
--------- ----- ------ ------ -------- --------
(mbbls) (mbbls) (mmcf) (mboe)
Proved Reserves
Producing 13,010 3,022 16,032 2,195 103,312 35,445
Non-Producing 437 573 1,010 147 16,682 3,937
Undeveloped 221 2,521 2,743 104 6,611 3,948
--------- ----- ------ ------ -------- --------
Total Proved 13,668 6,117 19,784 2,446 126,605 43,331
Probable 3,437 3,860 7,298 773 37,303 14,288
--------- ----- ------ ------ -------- --------

TOTAL Proved
plus Probable 17,105 9,977 27,082 3,218 163,908 57,618
--------- ----- ------ ------ -------- --------
--------- ----- ------ ------ -------- --------


Canada present value of reserves (a)(b)

Present Worth Value Before Tax(c) Discounted at
--------------------------------------------------------
0% 8% 10% 15% 20%
---------- ---------- ---------- ---------- ------------
($ 000's)
Proved
Reserves
Producing $ 787,859 $611,739 $582,441 $523,289 $478,101
Non-
Producing 57,745 39,867 37,083 31,647 27,631
Undeveloped 51,028 35,757 33,037 27,435 23,119
---------- ---------- ---------- ---------- ------------
Total Proved 896,632 687,363 652,561 582,371 528,852
Probable 295,481 173,312 156,536 125,489 104,225
---------- ---------- ---------- ---------- ------------

TOTAL Proved
plus
Probable $1,192,112 $860,675 $809,097 $707,860 $633,077
---------- ---------- ---------- ---------- ------------
---------- ---------- ---------- ---------- ------------

(a) Tables may not add due to rounding
(b) Present values include the effects of hedging
(c) Before Tax values presented for Canada since Provident is not
taxable in Canada


Provident's U.S. oil and natural gas reserves and present value of
estimated future cash flows based on forecast (escalated) price
assumptions are summarized below. Reserves and values reported are based
on 100 percent of the interests of Breitburn L.P. in the U.S. properties
as at December 31, 2004. Provident indirectly holds approximately 94.2
percent of the outstanding partnership interests of Breitburn L.P. with
the remaining approximately 5.8 percent of the partnership interests
held by Breitburn's co-founders and co-chief executive officers.



United States reserves summary (a)(b)

Gross Reserves
---------------------------------------------------------------------
Light & Heavy
Medium Crude Natural
Crude Oil Oil Oil NGLs Gas Boe
--------- ----- ------ ------ -------- --------
(mbbls) (mbbls) (mmcf) (mboe)
Proved
Reserves
Producing 28,135 1,649 29,784 74 7,744 31,149
Non-Producing 3,731 7 3,738 0 872 3,884
Undeveloped 8,375 1,970 10,345 606 10,660 12,728
--------- ----- ------ ------ -------- --------
Total Proved 40,241 3,626 43,868 681 19,276 47,761
Probable 9,770 2,916 12,686 371 7,863 14,367
--------- ----- ------ ------ -------- --------

TOTAL Proved
plus Probable 50,011 6,542 56,554 1,052 27,139 62,128
--------- ----- ------ ------ -------- --------
--------- ----- ------ ------ -------- --------


Net Reserves
---------------------------------------------------------------------
Light & Heavy
Medium Crude Natural
Crude Oil Oil Oil NGLs Gas Boe
--------- ----- ------ ------ -------- --------
(mbbls) (mbbls) (mmcf) (mboe)
Proved
Reserves
Producing 26,043 1,510 27,554 63 6,601 28,717
Non-Producing 3,433 7 3,439 0 752 3,565
Undeveloped 6,931 1,812 8,743 499 8,766 10,703
--------- ----- ------ ------ -------- --------
Total Proved 36,407 3,329 39,736 562 16,119 42,985
Probable 8,611 2,681 11,292 306 6,523 12,685
--------- ----- ------ ------ -------- --------
TOTAL Proved
plus Probable 45,019 6,009 51,028 868 22,642 55,670
--------- ----- ------ ------ -------- --------
--------- ----- ------ ------ -------- --------


(a) Tables may not add due to rounding.Reserves and values reported
are based on 100 percent of the interests of Breitburn L.P. in
the U.S. properties as at December 31, 2004. Provident
indirectly holds approximately 94.2 percent of the outstanding
partnership interests of Breitburn L.P. with the remaining
approximately 5.8 percent of the partnership interests held by
Breitburn's co-founders and co-chief executive officers.
(b) Reserves and values reported are based on 100 percent of the
interests of Breitburn L.P. in the U.S. properties as at
December 31, 2004. Provident indirectly holds approximately
94.2 percent of the outstanding partnership interests of
Breitburn L.P. with the remaining approximately 5.8 percent of
the partnership interests held by Breitburn's co-founders and
co-chief executive officers.


United States present value of reserves (a)(b)(d)

Present Worth Value Before Tax Discounted at
--------------------------------------------------------
0% 8% 10% 15% 20%
---------- ---------- ---------- ---------- ------------
($ 000's)
Proved
Reserves
Producing $335,771 $216,795 $195,120 $161,916 $139,566
Non-
Producing 67,298 32,611 28,296 20,733 15,920
Undeveloped 249,649 123,834 102,048 74,084 55,952
---------- ---------- ---------- ---------- ------------
Total Proved 652,718 373,240 325,465 256,733 211,438
Probable 311,602 135,226 110,398 77,952 58,506
---------- ---------- ---------- ---------- ------------
TOTAL
Proved plus
Probable $964,320 $508,466 $435,862 $334,685 $269,944
---------- ---------- ---------- ---------- ------------
---------- ---------- ---------- ---------- ------------


Present Worth Value After Tax(c) Discounted at
--------------------------------------------------------
0% 8% 10% 15% 20%
---------- ---------- ---------- ---------- ------------
($ 000's)
Proved
Reserves
Producing $303,042 $191,208 $170,375 $139,822 $119,457
Non-
Producing 18,646 2,426 486 -1,953 -3,215
Undeveloped 206,884 100,589 81,550 59,467 45,474
---------- ---------- ---------- ---------- ------------
Total Proved 528,571 294,224 252,411 197,336 161,715
Probable 232,441 93,262 73,046 50,157 37,023
---------- ---------- ---------- ---------- ------------
TOTAL
Proved plus
Probable $761,012 $387,486 $325,458 $247,493 $198,739
---------- ---------- ---------- ---------- ------------
---------- ---------- ---------- ---------- ------------

(a) Tables may not add due to rounding
(b) Values in Canadian dollars
(c) After tax values include U.S. State and Federal Taxes as well
as with holding tax on funds that flow back to Provident Energy
Ltd. in Canada.
(d) Reserves and values reported are based on 100 percent of the
interests of Breitburn L.P. in the U.S. properties as at
December 31, 2004. Provident indirectly holds approximately 94.2
percent of the outstanding partnership interests of Breitburn
L.P. with the remaining approximately 5.8 percent of the
partnership interests held by Breitburn's co-founders and
co-chief executive officers.


The following table summarizes the McDaniel's price forecast used in
evaluating Provident's reserves under escalated pricing assumptions:



Reserves pricing summary

WTI @ Alberta
US$/Cdn$ Cushing Light, Sweet Heavy Oil @ AECO
Exchange Oklahoma @ Edmonton Hardisty Spot Price
Rate US$/bbl Cdn$/bbl Cdn$/bbl Cdn$/GJ
---------------------------------------------------------------------
2005 0.83 42.00 49.60 29.40 6.45
2006 0.83 39.50 46.60 29.90 6.20
2007 0.83 37.00 43.50 27.90 6.05
2008 0.83 35.00 41.10 26.30 5.80
2009 0.83 34.50 40.50 25.90 5.70
---------------------------------------------------------------------


National Instrument 51-101

Oil and natural gas reserves estimation and reporting had been governed
by National Policy 2B (NP 2B) from the late 1970's until 2003. As a
result of concern expressed by many market participants over the quality
and consistency of oil and gas reserves estimates, the Alberta
Securities Commission established the Oil and Gas Taskforce in June
1998. The Taskforce, working with the Canadian Institute of Mining,
Metallurgy & Petroleum (CIM), and the Calgary chapter of the Society of
Petroleum Evaluations Engineers developed recommendations to standardize
reserve definitions, as well as the Canadian Oil and Gas Evaluation
(COGEH) handbooks to provide guidance for engineers and geologists on
recommended reserves booking practices. The Canadian Securities
Association proposed new standards that govern all aspects of reserves
disclosure in the form of National Instrument 51-101 (NI 51-101). The
evaluation practices applied to all of Provident's reserves comply with
NI 51-101.

Reserve definitions

The following outlines the main reserves definitions as per NI 51-101.

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

Closing Balance: Company or net interest reserves assigned at the end of
the period being reconciled.

Company Share: Includes working interest volumes and volumes equivalent
to royalty interests (RI) paid to others, but excludes volumes
equivalent to royalty interests received from others.

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

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

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

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

Infill Drilling: Additions to reserves resulting from capital
expenditures for infill drilling in previously discovered reservoirs
that were not drilled for enhanced recovery schemes and that were not
previously included in the initial reserves assignment.

Net Share: Includes the Company's working interests and volumes
equivalent to royalty interests received from others, but excludes
volumes equivalent to royalty interests (RI) paid to others.

Opening Balance: Company or net interest reserves reported in the
evaluation being reconciled to.

Production: Reserves reductions due to production during the time period
being reconciled.

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

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

Reserve life index (RLI)

The 2004 year end RLI's were determined by applying the average 2005
production rate from the McDaniel, NSA and CGA evaluations to the
remaining volumes as of January 1, 2005. The proved plus probable RLI's
for years prior to 2003 are based on established reserves under NP 2B
with probable reserves risked at 50 percent.

It is important to note that the long-term, stable cash flow from the
midstream services business significantly extends Provident's economic
life. For this reason economic life as a measure of Provident's future
cash flows is more representative than the typically referenced reserve
life index.

The following table illustrates the reserve volume and reserve life
index for Provident since its inception as a trust.



Provident consolidated reserve life index
Company share (WI + RI)

December 31,
Total Crude oil 2004 2003 2002 2001
---------------------------------------------------------------------
Proved Producing 7.2 3.6 3.7 4.0
Total Proved 9.0 4.6 4.9 6.6
Proved plus Probable 11.0 6.4 5.9 8.3

Natural gas liquids
---------------------------------------------------------------------
Proved Producing 4.9 5.3 4.8 4.6
Total Proved 6.1 5.6 5.2 5.3
Proved plus Probable 8.1 6.9 6.0 6.3

Natural gas
---------------------------------------------------------------------
Proved Producing 4.9 4.9 5.9 4.8
Total Proved 5.6 5.5 6.8 5.6
Proved plus Probable 6.9 6.8 7.7 6.7

Oil equivalent (6:1)
---------------------------------------------------------------------
Proved Producing 6.2 4.3 4.7 4.3
Total Proved 7.5 5.0 5.7 6.3
Proved plus Probable 9.3 6.6 6.7 7.8

Economic Life Index (a) 13.4 11.2 6.7 7.8

(a) Economic Life Index is based on a 25 year life for the Redwater
facilities which Provident acquired in 2003 with Oil & Gas and
Midstream weighting based on net present value discounted at 10
percent.


Canada reserve life index
Company share (WI + RI)

December 31,
Total Crude oil 2004 2003 2002 2001
---------------------------------------------------------------------
Proved Producing 3.8 3.6 3.7 4.0
Total Proved 4.3 4.6 4.9 6.6
Proved plus Probable 5.4 6.4 5.9 8.3

Natural gas liquids
---------------------------------------------------------------------
Proved Producing 4.8 5.3 4.8 4.6
Total Proved 4.7 5.6 5.2 5.3
Proved plus Probable 6.0 6.9 6.0 6.3

Natural gas
---------------------------------------------------------------------
Proved Producing 4.8 4.9 5.9 4.8
Total Proved 5.1 5.5 6.8 5.6
Proved plus Probable 6.3 6.8 7.7 6.7

Oil equivalent (6:1)
---------------------------------------------------------------------
Proved Producing 4.3 4.3 4.7 4.3
Total Proved 4.7 5.0 5.7 6.3
Proved plus Probable 5.8 6.6 6.7 7.8


United States reserve life index
Company share (WI + RI)

December 31,
Total Crude oil 2004 2003 2002 2001
---------------------------------------------------------------------
Proved Producing 16.9 -- -- --
Total Proved 22.1 -- -- --
Proved plus Probable 26.9 -- -- --

Natural gas liquids
---------------------------------------------------------------------
Proved Producing 8.9 -- -- --
Total Proved 15.0 -- -- --
Proved plus Probable 22.1 -- -- --

Natural gas
---------------------------------------------------------------------
Proved Producing 12.0 -- -- --
Total Proved 22.3 -- -- --
Proved plus Probable 27.2 -- -- --

Oil equivalent (6:1)
---------------------------------------------------------------------
Proved Producing 16.6 -- -- --
Total Proved 22.0 -- -- --
Proved plus Probable 26.8 -- -- --


Finding, development and acquisition costs

Under NI 51-101, the methodology to be used to calculate finding and
development costs (F&D) implies that F&D and finding, development and
acquisition costs (FD&A costs) incorporate changes in future development
capital (FDC) required to bring the proved undeveloped and probable
reserves to production.

Provident had three year average total proved plus probable finding,
development and acquisition (FD&A) costs of $10.68 per boe, including
Future Development Costs (FDC) and NI-51-101 revisions. We believe that
taking a three-year average of FD&A is the appropriate method in which
to look at reserve add costs because it takes into account more full
cycle economics as well as the means through which reserves are added.

In 2004 additions due to drilling were a significant contribution with
total proved additions of 3,079 Mboe and proved plus probable additions
of 4,108 Mboe. It is important to recognize that as an energy trust and
not an exploration oriented venture, Provident is naturally going to
focus capital and other resources on reserve promotes between
categories. In 2004, as a result of infill drilling we promoted over 213
MBOE of reserves into the proved developed producing category. The
associated capital, and any changes to it, have been accounted for in
the NI 51-101 calculation and is part of the ongoing development process
necessary to bring production on stream and create cash flow.

The table below presents F&D and FD&A costs for both proven and proved
plus probable reserves. Costs include all costs of exploring for and
developing reserves, including land costs. Acquisition costs include the
cash cost of acquiring reserves and the fair value of liabilities
assumed. The requirement under generally accepted accounting principles
to increase the book value of property plant and equipment and to record
an offsetting future tax liability when the purchase price paid on an
(usually corporate) acquisition exceeds the available tax pools. This
has not been added to FD&A costs. Goodwill was recorded on the
acquisitions as part of the purchase price allocation, and therefore
forms part of the costs of acquiring the reserves. NI 51-101 does not
specifically define reserve additions and does not contemplate nor
define acquisition costs. The following table presents reserve additions
both including reserve revisions and excluding reserve revisions. If
negative revisions exceed additions, the resultant negative number has
been excluded. In 2003, dispositions of oil and gas reserves exceeded
additions, and have also been excluded from the table.



Provident Consolidated
Three year
($ per boe) 2004 2003 2002 average (2)
---------------------------------------------------------------------
Finding and Development Costs
per boe(3) (includes FDCs)
Proven
------
Additions $21.20 $16.20 $14.39 $18.24
Additions including revisions $12.19 -(1) -(1) -(1)
Proved plus probable
--------------------
Additions $15.84 $22.05 $11.01 $15.42
Additions including revisions $12.79 $14.63 -(1) -(1)

Finding, development and
acquisition costs per boe
(includes FDCs)
Proven
------
Proven excluding revisions $14.55 -(1) $13.95 $12.63
Proven including revisions $14.07 -(1) $15.30 $13.28
Proved plus probable
--------------------
Proved plus probable excluding
revisions $11.71 -(1) $12.42 $10.39
Proved plus probable including
revisions $11.58 -(1) $13.91 $10.68
---------------------------------------------------------------------

(1) Revisions exceeded additions or dispositions exceeded
acquisition, therefore the calculation is not included in the
table
(2) Three year average is the average of 2002, 2003 and 2004. The
aggregate of the exploration and development costs incurred in
the most recent financial year and the change during that year in
estimated future development costs generally will not reflect
total finding and development costs related to reserves additions
for that year.
(3) Based on Company share reserves. BOEs may be misleading,
particularly if used in isolation. A BOE conversion ratio of 6
Mcf: 1 bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead.


Canada
Three year
($ per boe) 2004 2003 2002 average (2)
---------------------------------------------------------------------
Finding and Development Costs
per boe(3) (includes FDCs)
Proven
------
Additions $21.20 $16.20 $14.39 $18.24
Additions including revisions $12.19 -(1) -(1) -(1)
Proved plus probable
--------------------
Additions $15.84 $22.05 $11.01 $15.42
Additions including revisions $12.79 $14.63 -(1) -(1)

Finding, development and
acquisition costs per boe
(includes FDCs)
Proven
------
Proven excluding revisions $27.77 -(1) $13.95 $18.00
Proven including revisions $24.69 -(1) $15.30 $19.64
Proved plus probable
--------------------
Proved plus probable excluding
revisions $21.85 -(1) $12.42 $15.55
Proved plus probable including
revisions $20.96 -(1) $13.91 $16.38
---------------------------------------------------------------------

(1) Revisions exceeded additions or dispositions exceeded
acquisition, therefore the calculation is not included in the
table
(2) Three-year average is the average of 2002, 2003 and 2004. The
aggregate of the exploration and development costs incurred in
the most recent financial year and the change during that year in
estimated future development costs generally will not reflect
total finding and development costs related to reserves additions
for that year.
(3) Based on Company share reserves. BOEs may be misleading,
particularly if used in isolation. A BOE conversion ratio of 6
Mcf: 1 bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead.


United States(1)
($ per boe) 2004
---------------------------------------------------------------------
Finding, development and acquisition costs per boe(2)
(includes FDCs)
Proven
------
Proven excluding revisions $9.89
Proven including revisions $9.89
Proved plus probable
--------------------
Proved plus probable excluding revisions $8.19
Proved plus probable including revisions $8.19
---------------------------------------------------------------------

(1) All U.S. reserves included as acquisitions in 2004.
(2) Based on Company share reserves. BOEs may be misleading,
particularly if used in isolation. A BOE conversion ratio of 6
Mcf: 1 bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead.


Midstream services and marketing business segment

The assets

The Midstream business unit processes natural gas liquids (NGL) at the
Redwater fractionation, storage and transportation facility located near
Edmonton, Alberta. The integrated Redwater system is comprised of three
core assets:

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

- 43.3 percent ownership of the 38,500 bbl/d Younger NGL extraction
plant located at Taylor in northeastern British Columbia that supplies
16,700 bbl/d of net NGLs for processing at Redwater.

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

The majority of the property, plant and equipment are depreciated over
30 years on a straight-line basis reflecting the long useful life of
these assets.

Midstream and marketing services

Provident's midstream services offer customers several types of services
and contractual arrangements, which include:

Fee for service processing - ("Transportation and Fractionation - T&F")
In these arrangements, NGL owners (typically natural gas producers)
deliver to Provident their NGLs and pay fees for the transportation,
fractionation, short term storage and distribution of their NGL barrels.
The NGL owner is responsible for marketing their product.

Marketing Services: This service involves NGL owners delivering their
product to Provident with Provident taking title and paying the NGL
owner an amount that is a delivery price of raw NGLs that is discounted
to postings. The discounted purchase price that Provident pays for the
product covers the costs of transportation, fractionation, storage, and
marketing of the NGLs.

Storage: NGL owners pay fees to store their NGLs.

Transport and Distribution: NGL owners or purchasers pay fees to
transport NGLs through the LGS pipeline and use rail and truck loading
facilities.

Management estimates that marketing of third-party oil volumes, combined
with certain Provident crude oil volumes, will provide better producer
netbacks than can be achieved through third-party marketers.

The contracts

At the Redwater facility, approximately 75 percent of the available
capacity is contracted through fee-for-service or fixed margin
arrangements with major oil and natural gas producers and petrochemical
businesses. As a result of these contracts, approximately 68 percent of
Redwater's system capacity is contracted for 10 years or longer.

Fractionation plant capacity and throughput

The Redwater facility was constructed between 1996 and 1998. It is the
most modern facility of its type in Canada and is currently designed for
throughput capacity of 65,000 bpd of NGLs with an expectation to average
approximately 63,000 bpd.

Operations - throughput

In 2004, throughput at the Redwater fractionation facility averaged
55,120 bpd compared to 63,616 in the fourth quarter of 2003, the first
quarter in which the facility was owned by Provident. Outages on a
liquids gathering system and on a third-party delivery system
contributed to a reduction in mix inventory at the end of the year.
These outages were substantially mitigated through deliveries on
alternative pipelines.

Revenues

2004 product sales and services revenues of $840.2 million after
elimination of intersegment transactions include product sales related
to T&F processing and marketing, revenues generated through storage and
distribution services and oil sales generated through oil marketing
activities. The majority of NGL revenues are earned pursuant to the
long-term contracts and annual evergreen purchase and sales commitments.

Cost of goods sold

The cost of goods sold of $741.6 million after elimination of
intersegment transactions for the year relates 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 fixed margin 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 compared to
other North American facilities of this type. In 2004, operating costs
of $38.0 million included costs associated with a scheduled turnaround
at the Redwater plant. General and administrative expenses of $6.7
million for 2004 (2003 - $1.1 million), interest of $6.7 million for
2004 (year ended December 31 - $1.4 million), and depreciation of $9.6
million for 2004 (2003 - $2.2 million) consistently show 2004 expenses
exceed 2003 expenses because 2004 reflects a full year of operation
compared to three months of operations in 2003.

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

For 2004, Provident's Midstream business unit generated EBITDA of $50.1
million and cash flow from operations of $42.4 million. Actual EBITDA
performance exceeded management's 2004 EBITDA forecast of $38-$42
million. These full year results compare to fourth quarter 2003 EBITDA
of $10.2 million and cash flow of $8.9 million.

Management's 2005 forecast for Midstream EBITDA is $40 million.

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 ("EBITDA") Provident foreign ownership developments.

Foreign ownership

Since January 2002, we have seen increased trading volumes and levels of
ownership by non-residents of Canada. Based on information received from
our transfer agent and financial intermediaries in March 2005, an
estimated 75 percent of our outstanding trust units are held by
non-residents. However, this estimate may not be accurate as it is based
on certain assumptions and data from the security industry that does not
have a well-defined methodology to determine the residency of beneficial
holders of securities.

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 required that Provident have no 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 did 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
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.

Related party

Property sale

On December 30, 2004, at the conclusion of a competitive process,
Provident sold properties to a private company on whose board two of the
directors of Provident sit and in which they own shares. The properties
were sold for consideration of $3.5 million of which $0.5 million was
cash and $3.0 million consisted of 10,000,000 common shares valued at
$0.30 per share. The carrying value of these shares are included in
investments on the balance sheet. The transaction was recorded at fair
value.

Management internalization

On January 17, 2003, unitholders of the Trust approved a management
internalization transaction to eliminate the performance-based
arrangement between external management and the Trust for total non-cash
consideration of $18.0 million plus $0.6 million of transaction costs.
Total non-cash consideration of $18.0 million was settled with the
issuance of 1,682,242 exchangeable shares at a deemed price of $10.70
per share that are held in escrow and released 25 percent per year
commencing June 2003. The internalization was accretive to cash flow and
net asset value and also improves the long-term cost structure of the
Trust, which will be beneficial to the Trust's ability to attract
capital in a competitive marketplace and complete accretive
acquisitions. The transaction also increased ownership of the units held
by management and directors further aligning managements' interests with
those of unitholders.

Business prospects

Provident intends to execute a balanced portfolio strategy. In the COGP
business internal development projects with a board approved capital
budget of $68.8 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 $ 41.0
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.

Sensitivities

The following table shows the estimated sensitivity of 2005 cash flows
to changes in pricing, interest and volume with the assets and hedge
positions in place:



Change
000's per unit
---------------------------------------------------------------------
Pricing
WTI (+US$ 1.00) Oil $ 2,974 $ 0.02
AECO (+Cdn$ 0.25) Gas $ 4,460 $ 0.03
Interest (+/-1.0%) $ 1,677 $ 0.01
US exchange (+Cdn$ 0.01) $ 2,065 $ (0.01)
---------------------------------------------------------------------
Volume (000s)
Light/Medium Oil (+100 bpd) $ 921 $ 0.01
Heavy Oil (+100 bpd) $ 552 $ -
Natural Gas (+1.0 mmcfd) $ 1,372 $ 0.01
---------------------------------------------------------------------


Critical accounting policies

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

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

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

Property, plant and equipment

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

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

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

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

Asset retirement obligation

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

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

Changes in accounting policies

The following changes in accounting policy were adopted by Provident in
2004.

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.

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 financial statement effect of this
accounting treatment is outlined in this management's discussion and
analysis in the section entitled interest expense.

Hedging relationships

Effective January 1, 2004 the Trust adopted CICA accounting guideline
13, "Hedging relationships." This accounting guideline addresses the
identification, designation, documentation and effectiveness of hedging
relationships for the purpose of applying hedge accounting. In addition,
it establishes criteria for discontinuing the use of hedge accounting.
Under accounting guideline 13, hedging transactions must be documented
and it must be demonstrated that the hedges are sufficiently effective
to continue accrual accounting for positions hedged with derivatives.
Any derivative financial instruments that do not meet the hedging
criteria will be accounted for in accordance with Emerging Issues
Committee ("EIC") - 128, "Accounting for Trading, Speculative or
Non-Hedging Derivative Financial Instruments." These instruments will be
recorded on the balance sheet at fair value and changes in fair value
will be recognized in income in the period in which the change occurs.
In connection with the implementation of accounting guideline 13 the
Trust reviewed its Commodity Price Risk Management Program and
determined that none of the derivative instruments qualified for hedge
accounting.

At January 1, 2004 the Trust recorded an unrealized loss of $25.1
million in deferred charges on the Consolidated Balance Sheet that is
being recognized in income over the term of the previously designated
hedged items. The earnings impact was a $23.0 million loss before income
taxes for the year ended December 31, 2004 recorded in unrealized loss
on non-hedging derivative instruments on the Statement of Operations and
Accumulated Loss.

At December 31, 2004 the Trust recorded a non-hedging derivative
instrument payable of $24.5 million, being the mark to market loss
position of the Trust's non-hedging derivative instruments at that date.
As a result, the Trust recorded a loss on non-hedging derivative
instruments of $0.6 million for the year ended December 31, 2004.

Full cost accounting

Effective January 1, 2004 the Trust adopted CICA accounting guideline
16, "Oil and Gas Accounting - Full Cost." This accounting guideline
replaced CICA accounting guideline 5, "Full cost accounting in the oil
and gas industry." Accounting guideline 16 modifies how the ceiling test
calculation is performed. The recoverability of a cost centre is tested
by comparing the carrying value of the cost centre to the sum of the
undiscounted cash flows expected from the cost centre. If the carrying
value is not recoverable the cost centre is written down to its fair
value. Adopting accounting guideline 16 had no effect on the Trust's
financial results.

Unit based compensation

Provident accounts for the unit option plan using the fair value of the
option at the date of issue. Under the fair value method the amount to
be recognized as expense is determined at the time the options are
issued and is deferred and recognized in earnings over the vesting
period of the options with a corresponding increase in contributed
surplus. This method was adopted in 2003.

For the period from December 2003 to November 2004 the Trust used the
intrinsic method to estimate the compensation expense associated with
the unit option plan. The intrinsic value method re-valued unexercised
options based on the trading price of the trust's trust units at the
balance sheet date and amortized any change in value over the remaining
vesting period of the unexercised options. As the change in methodology
in 2004 is a change in estimate under accounting standards, the fair
value methodology has been applied prospectively without restatement of
prior periods.

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 unitholder's 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.

Transportation

Transportation costs incurred on Canadian oil and gas operations have
been classified as expenses in 2004. Comparative balances have been
restated.

Recent accounting pronouncements

The following new accounting guidelines or standards are applicable to
Provident but have not been implemented.

Variable interest entities ("VIEs")

In June 2003 the CICA issued Accounting Guideline 15 ("AcG-15")
"Consolidation of Variable Interest Entities". AcG-15 defines VIEs as
entities in which either; the equity at risk is not sufficient to permit
that entity to finance its activities without additional financial
support from other parties; or equity investors lack voting control, an
obligation to absorb expected losses or the right to receive expected
residual returns. AcG-15 harmonizes Canadian and U.S. GAAP and provides
guidance for companies consolidating VIEs in which they are the primary
beneficiary. The guideline is effective for all annual and interim
periods beginning on or after November 1, 2004. Provident does not
expect this guideline to have a material impact on the Trust.

Exchangeable shares

The CICA has issued a EIC, "Income trusts - exchangeable shares." The
Trust has not evaluated the effect that this standard might have on the
consolidated financial statements.

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; and

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

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 four quarters ended December 31, 2004 on both
the Toronto Stock Exchange and the American Stock Exchange:



Q1 Q2 Q3 Q4
------- ------- ------- -------
TSE - PVE.UN (Cdn$)
High $ 11.55 $ 11.77 $ 11.43 $ 11.96
Low $ 9.21 $ 10.29 $ 10.19 $ 10.56
Close $ 10.76 $ 10.29 $ 11.20 $ 11.37
Volume (000s) 13,156 25,275 26,858 21,851
---------------------------------------------------------------------
AMEX - PVX (US$)
High $ 9.06 $ 8.74 $ 8.96 $ 9.61
Low $ 7.59 $ 7.63 $ 7.70 $ 8.49
Close $ 8.24 $ 7.71 $ 8.88 $ 9.48
Volume (000s) 36,172 48,255 50,024 62,211
---------------------------------------------------------------------


Quarterly table
2004
----------------------------------------------------
----------------------------------------------------
($000s except per First Second Third Fourth YTD
unit amounts) Quarter Quarter Quarter Quarter Total
Financial
- consolidated
Revenue $234,432 $218,304 $287,686 $369,435 $1,109,857
Cash flow $ 36,269 $ 36,530 $ 54,076 $ 58,371 $ 185,246
Net income $ (6,144) $ (7,036) $ (4,317) $ 39,179 $ 21,682
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 $ 92,219 $ 295,529
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 $ 42,561 $ 143,365
Net income (loss) $(10,003) $(11,210) $(17,750) $ 28,111 $ (10,852)

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 $ 3,859 $ 4,174 $ 13,433 $ 11,068 $ 32,534

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

Midstream services
and marketing
Redwater
throughput (bpd) 58,640 48,452 55,759 56,599 55,120

(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


Quarterly table
2003
----------------------------------------------------
----------------------------------------------------
($000s except per First Second Third Fourth YTD
unit amounts) 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 $(10,832) $ 21,108 $ (4,285) $ 17,448 $ 23,439
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 $(10,832) $ 21,108 $ (4,366) $ 9,709 $ 15,619

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 $ $ $ 81 $ 7,739 $ 7,820

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

Midstream services
and marketing
Redwater
throughput (bpd) - - - 63,616 N/A

(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


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

As at As at
December 31, December 31,
2004 2003
------------- -------------
(restated
note 3)
Assets
Current assets
Cash $ 244 $ 45
Accounts receivable 143,142 118,890
Petroleum product inventory 17,151 24,206
Deferred derivative loss
(notes 2, 3 and 15) 2,144 -
Prepaid expenses 10,265 5,632
------------- -------------
172,946 148,773

Cash reserve for future site reclamation
(note 16) 1,454 1,829
Investments (note 2 and 13) 3,000 -
Deferred financing charges (note 3) 5,584 5,019
Property, plant and equipment (note 5) 1,299,654 884,891
Goodwill (note 4) 330,944 102,443
------------- -------------
$1,813,582 $1,142,955
------------- -------------
------------- -------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 171,412 $ 121,832
Cash distributions payable 15,416 8,389
Distribution payable to non-controlling
interest 271 -
Financial derivative instruments
(notes 2 and 3) 24,524 -
------------- -------------
211,623 130,221

Long-term debt (note 3 and 6) 432,206 356,573
Asset retirement obligation
(notes 2 and 8) 40,506 33,182
Future income taxes (note 12) 70,629 58,805
------------- -------------

Non-controlling interest 13,649 -


Unitholders' Equity
Unitholders' contributions (note 9) 1,438,393 803,299
Exchangeable shares (note 9) 34,439 19,518
Convertible debentures equity component
(note 3) 9,785 7,908
Contributed surplus (note 10) 2,002 1,305
Cumulative translation adjustment
(note 3) (28,848) -
Accumulated income (loss) 1,844 (19,838)
Accumulated cash distributions (note 11) (412,646) (248,018)
------------- -------------
1,044,969 564,174
------------- -------------
$1,813,582 $1,142,955
------------- -------------
------------- -------------


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

Year ended
December 31,
---------------------------
2004 2003
---------------------------
(restated
note 3)
Revenue (note 7)
Revenue $1,200,854 $ 455,263
Realized loss on financial derivative
instruments (68,944) (48,934)
Unrealized loss on financial derivative
instruments (22,053) -
---------------------------
1,109,857 406,329

Expenses
Cost of goods sold 741,641 153,147
Production, operating and maintenance 141,493 84,040
Transportation 5,087 5,447
General and administrative 27,104 15,365
Non-cash general and adminstrative
(note 10) 1,819 1,305
Management internalization (note 13) - 18,592
Interest on bank debt 11,816 9,733
Interest, accretion and amortization on
convertible debentures 16,608 9,955
Foreign exchange (gains) losses (2,224) 180
Depletion, depreciation and accretion 177,282 138,272
---------------------------
1,120,626 436,036
---------------------------

Loss before taxes (10,769) (29,707)
---------------------------

Capital taxes 5,921 3,332
Current and withholding taxes 1,282 -
Future income tax recovery (note 12) (40,577) (56,478)
---------------------------
(33,374) (53,146)
---------------------------

Net income before non-controlling interest 22,605 23,439
---------------------------
Non-controlling interest 923 -
---------------------------
Net income 21,682 23,439
---------------------------

Accumulated loss, beginning of year (4,029) (37,423)
Retroactive application of changes in
accounting policies (Note 3) (15,809) (5,854)
---------------------------
Accumulated loss, beginning of year,
restated (19,838) (43,277)
---------------------------
Accumulated income (loss), end of year $ 1,844 $ (19,838)
---------------------------
---------------------------

---------------------------
Net earnings per unit - basic $ 0.19 $ 0.34
------------- -------------
- diluted $ 0.19 $ 0.34
------------- -------------


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

Year ended
December 31,
---------------------------
2004 2003
---------------------------
(restated
note 3)
Cash provided by operating activities
Net income for the year $ 21,682 $ 23,439
Add non-cash items:
Depletion, depreciation and accretion 177,282 138,272
Amortization of deferred charges - 621
Debenture accretion and amortization of
deferred financing charges (note 6) 2,808 2,614
Non-cash general and administrative
(note 10) 1,819 1,305
Unrealized loss on non-hedging derivative
instruments (note 7) 22,053 -
Unrealized foreign exchange gain (744) -
Future income tax recovery (40,577) (56,478)
Non-controlling interest (note 4) 923 -
Management internalization (note 13) - 18,592
---------------------------
Cash flow from operations before changes
in working capital and site restoration
expenditures 185,246 128,365
Site restoration expenditures (3,219) (2,153)
Change in non-cash operating working
capital 5,796 (23,377)
---------------------------
187,823 102,835
---------------------------
Cash used for financing activities
Proceeds (repayments) of long-term debt (77,087) 49,300
Proceeds of bridge financing 158,184 -
Repayment of bridge financing (158,184) -
Declared distributions to unitholders (164,628) (129,612)
Declared distributions to non-controlling
interest (964) -
Issue of trust units, net of issue costs 320,976 220,262
Issue of debenture, net of costs 48,000 71,800
Change in non-cash financing working
capital 8,213 28
---------------------------
134,510 211,778
---------------------------

Cash used for investing activities
Expenditures on property, plant and
equipment (76,321) (31,628)
Acquisition of Olympia Energy Inc.
(note 4) (4,715) -
Acquisition of Viracocha Energy Inc.
(note 4) (1,993) -
Acquisition of Breitburn Energy LLC
(note 4) (165,649) -
Acquisition of Redwater (note 4) (1,300) (298,638)
Oil and gas property acquisitions (72,745) -
Acquisition of Provident Management Corp - (364)
Proceeds on disposition of oil and natural
gas properties 10,717 9,947
Reclamation fund contributions (2,844) (2,492)
Reclamation fund withdrawals 3,219 2,153
Payment of non-hedging derivative
instruments (23,302) -
Reimbursement for leasehold improvements - 1,437
Change in non-cash investing working
capital 12,799 4,975
---------------------------
(322,134) (314,610)
---------------------------

Increase in cash 199 3


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

December 31, 2004

1. Structure of the Trust

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

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

2. Significant accounting policies

(i) Principles of consolidation and investments

The consolidated financial statements include the accounts of the Trust
and Provident and its subsidiary Breitburn Energy Ltd. (Breitburn), and
are presented in accordance with Canadian generally accounting
principles.

The Trust has an investment in a private company representing 20 percent
of the total outstanding private company's shares. The Trust does not
have direct or joint control over the strategic operating, investing and
financing decisions of the private company, but does have significant
influence. The investment in the private company is accounted for using
the equity method.

(ii) Financial derivative instruments

All derivative financial instruments are recorded on the balance sheet
at fair value and changes in fair value are recognized in income as
unrealized gains (losses) on financial derivative instruments in the
period in which the change occurs. Actual gains (losses) are recorded as
realized gains (losses) on financial derivative instruments in the
period that the instrument is settled.

(iii) Property, plant & equipment

The Trust follows the full cost method of accounting for oil and natural
gas exploration and development activities, whereby all costs associated
with the acquisition and development of oil and natural gas reserves are
capitalized. Such costs include lease acquisition, lease rentals on
non-producing properties, geological and geophysical activities,
drilling of productive and non-productive wells, and tangible well
equipment. Gains or losses on the disposition of oil and gas properties
are not recognized unless the resulting change to the depletion and
depreciation rate is 20 percent or more. All other property, plant and
equipment, including midstream assets, are recorded at cost. Inventories
used to fill in cavern bottoms are presented as part of property, plant
and equipment and stated at historical cost. These inventories are not
depreciated.

a) Depletion, depreciation and accretion

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

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

b) Ceiling test

Effective January 1, 2004 the ceiling test calculation is performed by
comparing the carrying value of the cost centre to the sum of the
undiscounted proved reserve cash flows expected from the cost centre
using future price estimates. If the carrying value is not recoverable,
the cost centre is written down to its fair value. Fair value is
determined by the future cash flows from the proved plus probable
reserves discounted at the Trust's risk free interest rate. Any excess
carrying value of the assets on the balance sheet above fair value would
be recorded in depletion, depreciation and accretion expense as a
permanent impairment.

(iv) Joint Venture

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

(v) Inventory

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

(vi) Goodwill

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

(vii) Asset retirement obligation

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

(viii) Unit option plan

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

(ix) Unit appreciation rights plan

The Trust has established a unit appreciation rights plan (UAR's) for
certain employees of its U.S. subsidiary. Liabilities under the Trust's
UAR's are estimated at each balance sheet date, based on the amount of
UAR's that are in the money using the unit price as at that date.
Expenses are recorded through non-cash general and administrative costs,
with an offsetting amount in accounts payable.

(x) Trust unit calculations

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

The dilutive effect of convertible debentures is determined using the
"if-converted" method whereby if the current market price per unit is in
excess of the stated conversion price per unit the weighted-average
number of potential units assumed issued are included in the per unit -
diluted calculations. The units issued upon conversion are included in
the denominator of per unit - basic calculations from the date of
conversion. Consequently, units assumed issued are weighted for the
period the convertible debentures were outstanding, and units actually
issued are weighted for the period the units were outstanding.

(xi) Future income taxes

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

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

(xii) Revenue recognition

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

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

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

(xiii) Use of estimates

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

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

3. Changes in accounting policies and practices

(i) Financial derivative instruments

Effective January 1, 2004 the Trust adopted CICA accounting guideline
13, "Hedging relationships." This accounting guideline addresses the
identification, designation, documentation and effectiveness of hedging
relationships for the purpose of applying hedge accounting. In addition,
it establishes criteria for discontinuing the use of hedge accounting.
Under accounting guideline 13, hedging transactions must be documented
and it must be demonstrated that the hedges are sufficiently effective
to continue accrual accounting for positions hedged with derivatives.
Any derivative financial instruments that do not meet the hedging
criteria will be accounted for in accordance with Emerging Issues
Committee ("EIC") - 128, "Accounting for Trading, Speculative or
Non-Hedging Derivative Financial Instruments." These instruments will be
recorded on the balance sheet at fair value and changes in fair value
will be recognized in income in the period in which the change occurs.
In connection with the implementation of accounting guideline 13 the
Trust reviewed its Commodity Price Risk Management Program and did not
apply hedge accounting to its derivative instruments.

At January 1, 2004 the Trust recorded an unrealized loss of $25.1
million in deferred charges on the consolidated balance sheet that is
being recognized in income over the term of the previously designated
hedged items. For the period ending December 31, 2004, $23.0 million of
this deferred charge has been amortized.

At December 31, 2004 the Trust recorded a financial derivative
instrument payable of $24.5 million, that being the mark to market loss
position of the Trust's financial derivative instruments at that date.

(ii) Property, plant & equipment

Effective January 1, 2004 the Trust adopted CICA accounting guideline
16, "Oil and Gas Accounting - Full Cost." This accounting guideline
replaced CICA accounting guideline 5, "Full Cost Accounting in the Oil
and Gas Industry." Accounting guideline 16 modifies how the ceiling test
calculation is performed. The recoverability of a cost centre is tested
by comparing the carrying value of the cost centre to the sum of the
undiscounted proved reserve cash flows expected from the cost centre
using future price estimates. If the carrying value is not recoverable,
the cost centre is written down to its fair value determined by
comparing the future cash flows from the proved plus probable reserves
discounted at the Trust's risk free interest rate. Any excess carrying
value of the assets on the balance sheet above fair value would be
recorded in depletion, depreciation and accretion expense as a permanent
impairment. Adopting accounting guideline 16 had no effect on the
Trust's financial results.

(iii) 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 6 to the financial statements.

(iv) 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 unitholder's 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.

(v) Transportation

Transportation costs incurred on Canadian oil and gas operations have
been classified as expenses in 2004. Comparative balances have been
restated.

4. Acquisitions

(i) 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 9) 15,132
Trust units issued (note 9) 152,863
-----------
$ 172,710
-----------
-----------


(ii) 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 9) 15,132
Trust units issued (note 9) 145,701
-----------
$ 162,826
-----------
-----------


(iii) 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 (US$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.

(iv) Acquisition of Redwater

On September 30, 2003, Provident acquired Western Canadian midstream
assets ("Redwater") for $298.6 million. The purchase price was financed
through $35.8 million of long-term debt, $71.8 million of net proceeds
from the issuance of convertible debentures, and $191.1 million in net
proceeds from the issuance of 19,205,000 trust units. In 2004 an
additional $1.3 million of acquisition costs were incurred and allocated
to property, plant and equipment and financed by long-term debt.



Provident allocated the purchase price of Redwater as follows:

Net assets acquired
Petroleum product inventory $ 15,413
Property, plant and equipment
(includes acquisition costs of $6,763) 283,225
-----------
$ 298,638
-----------
-----------
The acquisition was financed by:
Revolving term credit facility (note 6) $ 35,768
Issuance of trust units issued for cash
(net of costs $10,582) (note 9) 191,070
Issuance of convertible debentures
(net of costs of $3,205) (note 6) 71,800
-----------
$ 298,638
-----------
-----------

5. Property, plant & equipment

Accumulated
depletion and Net Book
December 31, 2004 Cost depreciation value
---------------------------------------------------------------------
Oil and natural gas properties $1,567,902 $ 555,280 $1,012,622
Midstream assets 293,616 11,815 281,801
Office equipment 9,904 4,673 5,231
---------------------------------------------------------------------
Total $1,871,422 $ 571,768 $1,299,654
---------------------------------------------------------------------

Accumulated
depletion and Net Book
December 31, 2003 Cost depreciation value
---------------------------------------------------------------------
Oil and natural gas properties $ 990,568 $ 391,922 $ 598,646
Midstream assets 283,225 2,206 281,019
Office equipment 8,359 3,133 5,226
---------------------------------------------------------------------
Total $1,282,152 $ 397,261 $ 884,891
---------------------------------------------------------------------


Costs associated with unproved properties excluded from costs subject to
depletion as at December 31, 2004 totaled $31.2 million (December 31,
2003 - $16.4 million). Asset retirement costs of $29.4 million are
included in the property, plant and equipment (December 31, 2003 - $26.4
million).

An impairment test calculation was performed on the Trust's property,
plant and equipment at December 31, 2004 in which the estimated
undiscounted future net cash flows based on estimate future prices
associated with the proved reserves exceeded the carrying amount of the
Trust's oil and gas property plant and equipment.



The following table outlines prices used in the impairment test at
December 31, 2004:

Year Oil Gas NGL
---------------------------------------------------------------------

2005 $41.12 $ 7.93 $37.36
2006 $35.72 $ 6.65 $29.56
2007 $32.47 $ 6.20 $25.36
2008 $33.66 $ 6.17 $25.25
2009 $34.68 $ 6.28 $24.67


6. Long-term debt

Dec 31, 2004 Dec 31, 2003
------------------------------
Revolving term credit facility $ 262,750 $ 236,500
Convertible debentures 169,456 120,073
------------------------------
$ 432,206 $ 356,573
------------------------------
------------------------------


(i) Revolving term credit facility

Provident has a $410 million term credit facility with a syndicate of
Canadian chartered banks secured by oil and gas and midstream assets.
Interest rates under the terms of the credit facility are determined
quarterly based on the ratio of quarter end debt divided by the previous
quarter's cash flow annualized. At December 31, 2004, the rate was the
bank prime of 4.75 percent plus 0.50 percent. At December 31, 2003 the
facility totaled $335 million and in February 2004 a credit and consent
agreement restricted the borrowing base under the facility to $310
million. In June 2004 the facility increased to $370 million and at
September 30, 2004, the facility was increased $40 million to its
current level of $410 million. The additional $40 million of capacity is
intended to provide for a US dollar base rate loan.

Pursuant to the terms of the agreement, each year on or after May 24,
Provident can request the revolving period to be extended for a further
364 day period. If the lenders do not extend the revolving period, at
Provident's option, the credit facility is converted to a one year
non-revolving term credit facility at the end of the 364 day term, with
one-sixth of the loan balance due May 2006, one-twelfth due August 2006
and the remaining balance due at the end of the term period. As
collateral security, Provident has pledged a $750 million fixed and
floating charge debenture against all of its assets.

At December 31, 2004 Provident had $31 million in letters of credit
outstanding that guarantee Provident's performance under certain
commercial contracts associated with the marketing segment of the
midstream business unit. At December 31, 2003 Provident's letters of
credit totaled $12.3 million.

(ii) Convertible debentures

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.

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.

On April 11, 2002 the Trust issued $64.4 million of unsecured
subordinated convertible debentures ($61.4 million net of issue costs)
with a 10.5 percent coupon rate maturing May 15, 2007. 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 $10.70 per trust unit prior to May 15, 2007, 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 $63.2 million. The difference between
the fair value and proceeds of $1.2 million was recorded as equity.

The Trust may elect to satisfy interest and principal obligations by the
issuance of trust units. During 2004, $0.12 million of debentures were
converted to trust units at the election of debenture holders (2003-
$14.35 million).



7. Revenue
Year ended
December 31,
-----------------------------
2004 2003
------------- -------------
Gross production revenue $ 449,869 $ 355,941
Product sales and service revenue 840,184 172,191
Royalties (89,199) (72,869)
------------- -------------
Revenue 1,200,854 455,263
------------- -------------
Realized loss on financial derivative
instruments (68,944) (48,934)
Unrealized loss on financial derivative
instruments (22,053) -
------------- -------------
$ 1,109,857 $ 406,329
------------- -------------
------------- -------------

Change in unrealized gain on financial
derivative instruments $ 937 $ -
Amortization of loss on financial
derivative instruments (note 15) (22,990) -
------------- -------------
Unrealized loss on financial derivative
instruments $ (22,053) $ -
------------- -------------
------------- -------------

The realized loss on financial derivative instruments for the year
ended December 31, 2004 of $68.9 million (2003 - $48.9 million
realized loss) relates to the cash settlement on derivative
instruments.


8. Asset retirement obligation

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

The total undiscounted amount of future cash flows required to settle
asset retirement obligations related to oil and gas operations is
estimated to be $130.4 million. Payments to settle oil and gas asset
retirement obligations occur over the operating lives of the assets
estimated to be from two to 20 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.



For the year ended
December 31,

2004 2003
-----------------------------
Carrying amount, beginning of period $ 33,182 $ 32,645
Oil and gas producing corporate
acquisitions 12,171 -
Change in estimate (2,429) -
Increase in liabilites incurred during
the period 166 519
Accretion expense 2,387 2,171
Settlement of liabilities during the
period (4,971) (2,153)
-----------------------------
Carrying amount, end of period $ 40,506 $ 33,182
-----------------------------
-----------------------------


9. Unitholders contributions and exchangeable shares

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

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. Proceeds from the issue
were initially used to pay down Provident's bank debt and throughout
2004 have been used to finance the 2004 capital program.

On June 1, 2004 the Trust issued 13.4 million units (at an ascribed
value of $152.9) and a further 12.8 million units (at an ascribed value
of $145.7 million) as part of the consideration to acquire the
outstanding shares of Olympia Energy Inc. and Viracocha Energy Inc.
respectively. 1.325 million exchangeable shares of Provident Energy Ltd.
were issued pursuant to each transaction for a total of 2.65 million
additional exchangeable shares. The exchangeable shares will be
automatically exchanged for Trust Units on January 15, 2006, subject to
extension at the option of the Offeror. The exchange ratio for these
shares is calculated with reference to the distributions.

On July 6, 2004 the Trust issued 13.1 million units at $10.40 per unit
for proceeds of $136.2 million ($129.4 million net of issue costs)
pursuant to a June 17, 2004 public offering. Proceeds from the issue
applied to pay down the bridge financing used in the Breitburn Energy
LLC acquisition.

On October 4, 2004 the Trust issued 11.48 million units at $10.95 per
unit, for net proceeds (after underwriters' fees) of $119.4 million.
Proceeds were used to fund the acquisition of the Orcutt property in
California ($58.5 million) and to repay bank debt.

In 2004 the Trust issued 4.2 million units related to Provident's DRIP
program, conversion of exchangeable shares to units, conversion of
convertible debentures to units and units issued pursuant to Provident's
Unit Option Plan. The net increase in unitholders' contributions
associated with these activities was $40.0 million.

During 2003 the Trust issued 19,205,000 units (16,700,000 on September
30, 2003 and 2,505,000 on exercise of underwriters options) for gross
proceeds of $201.7 million, in a financing concurrent with the purchase
of the Redwater assets (Note 4).

On January 17, 2003 Provident Energy Ltd., a subsidiary, issued 1.7
million exchangeable shares as consideration for the acquisition of
Provident Management Corp. (see Note 13). The conversion ratio for the
exchangeable shares for the period January 17 to February 14, 2003 was
equal to one trust unit for one exchangeable share, and is increased on
each date a distribution is paid by the trust. The exchangeable shares
are held in escrow and are releasable as to 25 percent per year
beginning on June 30, 2003, and are releasable or may be forfeited in
certain other limited circumstances.

In 2003 the Trust issued 9.9 million units related to Provident's DRIP
program, conversion of exchangeable shares to units, conversion of
convertible debentures to units and units issued pursuant to Provident's
Unit Option Plan. The net increase in unitholders' contributions
associated with these activities was $98.9 million.



Year ended December 31,
2004 2003
---------------------- ----------------------
Trust Units Number Amount Number Amount
of Units (000s) of Units (000s)
---------------------- ----------------------
Balance at beginning
of period 82,824,688 $ 803,299 53,729,335 $ 513,835
Issued to acquire
Olympia Energy Inc.
(note 4) 13,385,579 152,863 - -
Issued to acquire
Viracocha Energy
Ltd. (note 4) 12,758,386 145,701 - -
Issued for cash 29,080,000 312,346 19,205,000 201,653
Exchangeable share
conversions 1,633,312 15,343 5,726,525 55,518
Issued pursuant to
unit option plan 638,991 4,677 202,446 1,626
Issued pursuant to
the distribution
reinvestment plan 1,745,418 18,250 2,478,956 25,880
To be issued
pursuant to the
distribution
reinvestment plan 148,496 1,616 141,361 1,528
Debenture
conversions 11,378 124 1,341,065 14,350
Unit issue costs - (15,826) - (11,091)
----------- ---------- ---------- -----------
Balance at end of
period 142,226,248 $1,438,393 82,824,688 $ 803,299
----------- ---------- ---------- -----------
----------- ---------- ---------- -----------

Year ended December 31,
2004 2003
Exchangeable shares ---------------------- ----------------------
Provident Number Amount Number Amount
Acquisitions Inc. of Units (000s) of Units (000s)
----------- ---------- ---------- -----------

Balance at beginning
of period 534,357 $ 5,829 5,227,844 $ 57,036
Converted to trust
units (197,481) (2,154) (4,693,487) (51,207)
----------- ---------- ---------- -----------
Balance, end of period 336,876 3,675 534,357 5,829
----------- ---------- ---------- -----------
Exchange ratio, end
of period 1.42501 1.2517
----------- ---------- ---------- -----------
Trust units issuable
upon conversion, end
of period 480,052 $ 3,675 668,855 $ 5,829
----------- ---------- ---------- -----------
----------- ---------- ---------- -----------

Exchangeable shares Number Amount Number Amount
Provident Energy Ltd. of Units (000s) of Units (000s)
----------- ---------- ---------- -----------
Balance at beginning
of period 1,279,227 $ 13,689 - $ -
Issued to acquire
Provident Management
Corp. (note 13) - - 1,682,242 18,000
Converted to trust
units (640,753) (6,856) (403,015) (4,311)
----------- ---------- ---------- -----------
Balance, end of
period 638,474 6,833 1,279,227 13,689
----------- ---------- ----------
Exchange ratio,
end of period 1.35099 - 1.18663
----------- ---------- ---------- -----------
Trust units issuable
upon conversion, end
of period 862,572 $ 6,833 1,517,969 $ 13,689
----------- ---------- ---------- -----------
----------- ---------- ---------- -----------

Exchangeable shares
(Series B)
Number Amount Number Amount
Provident Energy Ltd. of Units (000s) of Units (000s)
----------- ---------- ---------- -----------
Balance at beginning
of period - $ - - $ -
Issued to acquire
Olympia Energy Inc.
(note 4) 1,325,000 15,132 - -
Issued to acquire
Viracocha Energy
Inc. (note 4) 1,325,000 15,132 - -
Converted to trust
units (554,729) (6,333)
----------- ---------- ---------- -----------
Balance, end of
period 2,095,271 23,931 - -
----------- ---------- ---------- -----------
Exchange ratio,
end of period 1.06742 - - -
----------- ---------- ---------- -----------
Trust units issuable
upon conversion,
end of period 2,236,534 $ 23,931 - $ -
----------- ---------- ---------- -----------
----------- ---------- ---------- -----------

Total Trust unit
issuable upon
conversion of all
exchangeable shares,
end of period 3,579,158 $ 34,439 2,186,824 $ 19,518
----------- ---------- ---------- -----------
----------- ---------- ---------- -----------


The per trust unit amounts for 2004 were calculated based on the
weighted average number of units outstanding of 116,627,982 which
includes the shares exchangeable into trust units (2003 - 68,448,203).
The diluted per trust unit amounts for 2004 are calculated including an
additional 179,428 trust units (2003 - 50,098) for the effect of the
unit option plan. Provident's convertible debentures are not included in
the computation of diluted earnings per unit as their effect is
anti-dilutive.

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 except for options granted to existing employees which
vest immediately.



Year ended
December 31,
----------------------------------------
2004 2003
------------------- --------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
--------- -------- --------- ---------
Outstanding,
beginning of period 4,008,744 $11.06 796,810 $10.86
Granted 1,909,067 10.89 3,443,550 11.09
Exercised (638,991) 10.96 (202,446) 10.62
Cancelled (78,489) 11.25 (29,170) 11.18
--------- -------- --------- ---------
Outstanding,
end of period 5,200,331 11.01 4,008,744 11.06
--------- -------- --------- ---------
Exercisable at
end of period 2,620,941 $11.05 1,535,004 $11.07
--------- -------- --------- ---------
--------- -------- --------- ---------


At December 31, 2004, the Trust had 5,200,331 options outstanding with
strike prices ranging between $8.40 and $12.39 per unit. The weighted
average remaining contractual life of the options is 2.71 years and the
weighted average exercise price is $11.01 per unit excluding average
potential reductions to the strike prices of $1.08 per unit.

At December 31, 2003, the Trust had 4,008,744 options outstanding with
strike prices ranging from $8.40 and $12.39 per unit. The weighted
average remaining contractual life of the options was 3.09 years and the
weighted exercise price was $11.06 per unit excluding average potential
reductions to the strike prices of $1.26 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.

In 2004 the Trust recorded unit-based compensation expense (non-cash
general and administrative) of $1.2 million, for the 5.4 million options
granted on or after January 1, 2003 (2003 - $1.3 million) net of the
fourth quarter's compensation recovery of $0.3 million (2003 - nil).

As at December 31, 2004, 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 $3.6 million:



2004 Granted Options 2003 Granted Options
---------------------------------------------------------------------
Expected annual dividend 8.00% 8.00%
Expected volatility 20.18% 19.46%
Risk - free interest rate 3.30% 3.66%
Expected life of option (yrs) 3.31 3.31
Expected forteitures - -
Fair Value of Granted Options $1.2 million $2.4 million
---------------------------------------------------------------------


In the fourth quarter, 2004 the fair value calculation resulted in a
compensation recovery of $0.3M. This difference resulted from the fair
value expense of $0.9 million compared to the $1.2 million recorded as
compensation expense for the period ending September 30, 2004 under the
intrinsic value methodology. Fourth quarter compensation expense
utilizing the fair value based method was $0.3M. The remaining fair
value of the rights of $1.1 million, less any future cancellations, will
be recognized in earnings over the remaining vesting period the rights
outstanding. The following table reconciles the movement in the
contributed surplus balance:



(Cdn$ 000's) 2004 2003
--------------------------
Contributed surplus, beginning of the year $ 1,305 $ -
Compensation expense, net of recovery 1,190 1,305
Benefit on options exercised charged to
unitholders' equity (493) -
--------------------------
Balance, end of year $ 2,002 $ 1,305
--------------------------
--------------------------


(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. These prices
are denominated in US dollars and are based on quoted US distributions
and market prices.

The following table summarizes the information about UAR's



As at December 31, 2004
---------------------------------------------------------------------
Number of Units Weighted Average
Appreciation Rights Exercise Price (US$)
---------------------------------------------------------------------
Outstanding, beginning of year - -
Granted 976,000 $9.59
Exercised - -
Cancelled - -
---------------------------------------
Outstanding, end of year 976,000 $9.59
Exercisable, end of year - -

Weighted average remaining
contract life 3.48
Average potential reductions
to exercise price $0.35
---------------------------------------------------------------------


The fair value associated with the UAR's is expensed in the statement of
income over the vesting period. During the year, the Trust recorded
compensation costs of $0.8 million with respect to the outstanding UAR's
(2003 - nil).



11. Reconciliation of cash flow and distributions

Year ended
December 31,
-------------------------
2004 2003
-------------------------
Cash provided by operating activities $ 187,823 $ 102,835
Change in non cash working capital (5,796) 23,377
Site restoration expenditures 3,219 2,153
-------------------------
Cash flow from operations 185,246 128,365
Cash (reserved) used for financing and
investing activities (20,618) 1,247
-------------------------
Cash distributions to unitholders 164,628 129,612
Accumulated cash distributions,
beginning of period 248,018 118,406
-------------------------
Accumulated cash distributions,
paid and declared, end of period $ 412,646 $ 248,018
-------------------------


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

12. Future income taxes

Under this method, future income tax assets and liabilities are
recognized based on the estimated tax effects of temporary differences
in the carrying value of assets and liabilities, reported in the
financial statements of the corporate subsidiaries, and their respective
tax bases, using income tax rates substantively enacted on the
consolidated balance sheet date:



December 31,
-------------------------
2004 2003
-------------------------
Petroleum and natural gas properties,
production facilities and other $ 70,301 $ 57,401
Midstream facilities 328 1,404
-------------------------
$ 70,629 $ 58,805
-------------------------
-------------------------


The income tax provision differs from the expected amount calculated by
applying the Canadian combined federal and provincial income tax rate of
38.87 percent (2003 - 40.6 percent) as follows:



Year ended
-------------------------
2004 2003
-------------------------
Expected income tax recovery $ (4,186) $ (8,019)
Increase (decrease) resulting from:
Non-deductible Crown charges and
other payments 17,087 14,226
Federal resource allowance (7,535) (8,563)
Alberta Royalty Tax Credit (194) (183)
Income of the Trust and other (41,336) (44,050)
Capital Taxes 5,921 3,332
Witholding tax and other 1,282 -
Income tax rate changes (4,413) (9,889)
-------------------------
$ (33,374) $ (53,146)
-------------------------


13. Related party transactions

On December 30, 2004, at the conclusion of a competitive process,
Provident sold properties to a private company on whose board two of the
directors of Provident sit and in which they own shares. The properties
were sold for consideration of $3.5 million of which $0.5 million was
cash and $3.0 million consisted of 10,000,000 common shares valued at
$0.30 per share. The carrying value of these shares are included in
investments on the balance sheet. The transaction was recorded at fair
value.

Until January 17, 2003 the Trust was actively managed by Provident
Management Corporation (the "Manager"), and in accordance with the terms
of the management agreement, the Manager was entitled to receive a base
fee in the amount of two percent of the operating cash flow of
Provident, plus a total return fee based on distributions and unit price
performance during the period. Pursuant to the management fee amending
agreement approved in conjunction with the management internalization
transaction, the base fee paid for the period January 1 to October 31,
2002 was $1.8 million and $0.5 million for the period November 1 to
December 31, 2002, for a total base fee of $2.3 million. The total
return fee for 2002 was restricted to $9.0 million, payable by way of
$4.0 million in cash and 467,290 trust units valued at $5.0 million. The
Manager was reimbursed for administration expenses, which totaled
$264,242 in 2002.

On January 17, 2003, Provident acquired all the issued and outstanding
shares of Provident Management Corporation, Manager of the Trust and
Provident, for consideration of $18.0 million payable with the issuance
of 1,682,242 exchangeable shares. The exchangeable shares are held in
escrow and are releasable as to 25 percent per year beginning on June
30, 2003, and are releasable or may be forfeited in certain other
limited circumstances. This management internalization transaction
eliminates external management fees effective January 1, 2003. The share
purchase agreement as a condition of closing provides for executive
employment contracts for the former shareholders of Provident Management
Corporation. The full cost of this transaction, $18.6 million including
transaction costs of $0.6 million, was expensed in 2003.

14. Comparative balances

Certain comparative numbers have been restated to conform to the current
year presentation.

15. Financial instruments and hedging

Financial instruments of the Trust carried on the consolidated balance
sheet consist mainly of cash and cash equivalents, accounts receivable,
reclamation fund investments, current liabilities, other long-term
liabilities, asset retirement obligations, commodity and foreign
currency contracts and long-term debt. Except as noted below, as at
December 31, 2004 and 2003, there were no significant differences
between the carrying value of these financial instruments and their
estimated fair value.

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

At January 1, 2004 the Trust adopted CICA accounting guideline 13
"Hedging relationships" resulting in the recognition of an unrealized
loss of $25.1 million in deferred charges on the consolidated balance
sheet that is being amortized to income in the same period as the
corresponding losses associated with the hedged items.



Deferred derivative loss
Non-hedging derivative liability, January 1, 2004 $ 25,134
Derivative instruments amortized (22,990)
--------
Deferred derivative loss, December 31, 2004 $ 2,144
--------
--------


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

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

(i) Commodity price

a) Crude oil

For 2004, Provident paid out $56.2 million to settle various oil market
based contracts on an aggregate volume of 2,729,700 barrels. For 2003,
Provident paid out $23.9 million to settle various oil market based
contracts on an aggregate volume of 1,867,500 barrels. The estimated
value of contracts in place if settled at market prices at December 31,
2004 would have resulted in an opportunity cost of $25.2 million
(December 31, 2003 -$21.1 million). The contracts in place at December
31, 2004 are summarized in the following table:



COGP
---------------------------------------------------------------------
Year Product Volume Terms Effective Period
---------------------------------------------------------------------
Light January 1 -
2005 Oil 2,750 Bpd WTI US $26.07 per bbl(1) December 31
---------------------------------------------------------------------
Costless collar January 1 -
500 Bpd US $26.00-$30.10 per bbl December 31
---------------------------------------------------------------------


USOGP (BreitbBurn)
---------------------------------------------------------------------
Year Product Volume Terms Effective Period
---------------------------------------------------------------------
Light Costless collar January 1 -
2005 Oil 500 Bpd US$30.00-$39.80 per bbl December 31
---------------------------------------------------------------------
Costless collar January 1 -
500 Bpd US$30.00-$39.50 per bbl December 31
---------------------------------------------------------------------
Costless collar January 1 -
500 Bpd US$30.00-$39.37 per bbl December 31
---------------------------------------------------------------------
Costless collar January 1 -
500 Bpd US$30.00-$40.00 per bbl December 31
---------------------------------------------------------------------
January 1 -
750 Bpd Puts US $40.00 per bbl December 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.


b) Natural Gas

For 2004, Provident paid $10.4 million to settle various natural gas
market based contracts on an aggregate of 10,946,000 gigajoules ("GJ").
For 2003, Provident received $25.0 million to settle various natural gas
market based contracts on an aggregate of 23,063,900 gigajoules ("GJ").
As at December 31, 2004 the estimated value of contracts in place
settled at market prices at December 31 would have resulted in an
opportunity gain of $0.3 million (December 31, 2003 - an opportunity
cost of $4.1 million). The contracts in place at December 31, 2004 are
summarized in the following table:



---------------------------------------------------------------------
Year Product Volume Terms Effective Period
---------------------------------------------------------------------
Natural January 1 -
2005 Gas(2) 3,000 Gjpd Cdn $5.90 per gj March 31
---------------------------------------------------------------------
Costless collar January 1 -
3,000 Gjpd Cdn $5.25-$7.10 per gj March 31
---------------------------------------------------------------------
Costless collar January 1 -
2,000 Gjpd Cdn $5.50-$7.29 per gj March 31
---------------------------------------------------------------------
Costless collar January 1 -
2,000 Gjpd Cdn $5.50-$7.40 per gj March 31
---------------------------------------------------------------------
Costless collar January 1 -
1,000 Gjpd Cdn $5.50-$7.60 per gj March 31
---------------------------------------------------------------------
Costless collar January 1 -
2,000 Gjpd Cdn $5.50-$7.38 per gj March 31
---------------------------------------------------------------------
January 1 -
600 Gjpd Cdn $5.39 per gj October 31
---------------------------------------------------------------------
Costless collar January 1 -
2,000 Gjpd Cdn $5.50-$6.88 per gj October 31
---------------------------------------------------------------------
Costless collar January 1 -
5,000 Gjpd Cdn $6.00-$9.10 per gj January 31
---------------------------------------------------------------------
April 1 -
5,000 Gjpd Puts Cdn $6.50 per gj(1) October 31
---------------------------------------------------------------------
Participating Swaps April 1 -
5,000 Gjpd Cdn $6.00 per gj(3) October 31
---------------------------------------------------------------------


c) Other

Provident paid $4.8 million to settle various midstream and marketing
contracts which were entered into to fix prices on product sales.



---------------------------------------------------------------------
Year Product Volume Terms Effective Period
---------------------------------------------------------------------
US $0.88077 per usg January 1 -
2005 Propane 52,000 Bbls (US$36.99 per bbl)(1) January 31
---------------------------------------------------------------------
Foreign Sell US $6,500,000 January 1 -
Exchange @ $1.24128 (1) March 24
---------------------------------------------------------------------
Avg Rate Forward January 25, 2005 -
US $4,200,000 + 3 pts January 25, 2006
---------------------------------------------------------------------

---------------------------------------------------------------------
January 1 -
Power 2.5 MW/h $45.875 MW/h December 31
---------------------------------------------------------------------


d) Foreign exchange contracts

Provident had foreign exchange sell contracts in place in 2004 for a
total gain of $2.3 million. As at December 31, 2004 the estimated value
of contracts in place settles at foreign exchange rates at December 31
would have resulted in an opportunity gain of $0.2 million. The foreign
exchange gains have been included in note 18, as component of realized
gain or loss on non-hedging derivative instruments and allocated to
their respective business segments.

16. Cash reserve for future site reclamation

Provident established a cash reserve effective May 1, 2001 for future
site reclamation expenditures. In accordance with the royalty agreement,
Provident funds the reserve by paying $0.25 per barrel of oil equivalent
produced on a 6:1 basis into a segregated cash account. Actual
expenditures incurred are then funded from the cash in this account. For
the year ended December 31, 2004, $2.8 million was contributed to the
reserve and actual expenditures totaled $3.2 million. For the year ended
December 31, 2003, $2.5 million was added to the cash reserve and actual
expenditures totaled $2.2 million.

17. Commitments

Provident has office lease commitments that extend through April 2013.
Future minimum lease payments for the following five years are: 2005 -
$2.4 million; 2006 - $2.7 million; 2007 - $2.8 million, 2008 - $2.9
million; 2009 - $3.1 million, and $2.5 million thereafter.

18. 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 book value.



Year ended December 31, 2004
------------------------------------------
Canada Oil United States
and Natural Oil and Total Oil and
Gas Natural Gas Natural Gas
Production Production Production
------------------------------------------
Revenue

Gross production revenue $ 405,181 $ 44,688 $ 449,869
Royalties (85,190) (4,009) (89,199)
Product sales and service
revenue - - -
Realized gain/(loss) on
financial derivative (65,366) (425) (65,791)
instruments
------------------------------------------
254,625 40,254 294,879

Expenses

Cost of goods sold - - -
Operating expenses 90,330 13,173 103,503
Transportation 5,087 - 5,087
Foreign exchange (gain) loss (4) (2,239) (2,243)
General and administrative 16,439 4,113 20,552
------------------------------------------
111,852 15,047 126,899
------------------------------------------
Earnings (loss) before
interest, taxes, depletion,
depreciation, accretion and
non-cash revenue 142,773 25,207 167,980

Non-cash revenue

Unrealized gain/(loss)
on non-hedging derivative
instruments 3,788 (3,182) 606
Amortization of gain/(loss)
on non-hedging derivative
instruments (22,990) - (22,990)
------------------------------------------
(19,202) (3,182) (22,384)
------------------------------------------

Other expenses

Depletion, depreciation and
accretion 160,271 7,402 167,673
Interest on long-term debt &
convertible debentures 16,338 2,547 18,885
Accretion and amortization on
convertible debentures 1,801 175 1,976
Unrealized foreign exchange
(gain) loss (744) (744)
Non-cash general and
administrative 877 822 1,699
Capital taxes 5,292 - 5,292
Current and withholding taxes - 1,201 1,201
Future income tax expense
(recovery) (40,457) - (40,457)
------------------------------------------
144,122 11,403 155,525
Non-controlling interest - 923 923
------------------------------------------
Net income (loss) for
the year $ (20,551) 9,699 $ (10,852)
------------------------------------------
------------------------------------------

Selected balance sheet items


Capital Assets

Property, plant and
equipment net $ 763,306 $ 254,547 $ 1,017,853
Goodwill $ 330,944 $ - $ 330,944


Capital Expenditures
Property, plant and
equipment net $ 61,454 $ 12,410 $ 73,864
Property, plant and
equipment through
corporate acquisitions $ 272,259 $ 214,261 $ 486,520

Goodwill additions $ 228,501 $ - $ 228,501

Working capital
Accounts receivable $ 78,299 $ 11,137 $ 89,436
Petroleum product inventory - - -
Accounts payable and
accrued liabilities
$ 101,668 $ 28,639 $ 130,307
Long-term debt $ 274,683 $ 74,464 $ 349,147


Year ended December 31, 2004
------------------------------------------
Midstream
Services and Inter-segment
Marketing Elimination Total
------------------------------------------
Revenue

Gross production revenue $ - $ - $ 449,869
Royalties - - (89,199)
Product sales and
service revenue 1,031,019 (190,835) 840,184
Realized gain/(loss) on
financial derivative (3,153) - (68,944)
instruments
------------------------------------------
1,027,866 (190,835) 1,131,910

Expenses

Cost of goods sold 932,476 (190,835) 741,641
Operating expenses 37,990 - 141,493
Transportation - - 5,087
Foreign exchange (gain) loss 763 - (1,480)
General and administrative 6,552 - 27,104
------------------------------------------
977,781 (190,835) 913,845
------------------------------------------
Earnings (loss) before
interest, taxes, depletion,
depreciation, accretion and
non-cash revenue 50,085 - 218,065

Non-cash revenue

Unrealized gain/(loss) on
non-hedging derivative
instruments 331 - 937
Amortization of gain/(loss)
on non-hedging derivative
instruments - - (22,990)
------------------------------------------
331 - - (22,053)
------------------------------------------

Other expenses

Depletion, depreciation and
accretion 9,609 - 177,282
Interest on long-term debt &
convertible debentures 6,731 - 25,616
Accretion and amortization on
convertible debentures 832 2,808
Unrealized foreign exchange
(gain) loss - (744)
Non-cash general and
administrative 120 - 1,819
Capital taxes 629 - 5,921
Current and withholding taxes 81 - 1,282
Future income tax expense
(recovery) (120) - (40,577)
------------------------------------------
17,882 - 173,407
Non-controlling interest 923
------------------------------------------
Net income (loss) for the
year $ 32,534 $ - $ 21,682
------------------------------------------
------------------------------------------


Selected balance sheet items

Capital Assets

Property, plant and
equipment net $ 281,801 $ - $ 1,299,654
Goodwill $ - $ - $ 330,944


Capital Expenditures
Property, plant and
equipment net $ 2,457 $ - $ 76,321
Property, plant and
equipment through
corporate acquisitions $ 1,300 $ - $ 487,820

Goodwill additions $ - $ - $ 228,501

Working capital
Accounts receivable $ 67,017 $(13,311) $ 143,142
Petroleum product inventory 17,151 - 17,151
Accounts payable and
accrued liabilities
$ 54,416 $(13,311) $ 171,412
Long-term debt $ 83,059 $ - $ 432,206


Year ended December 31, 2003
----------------------------------------------

Oil and Midstream
Natural Services Inter-
Gas and segment
Production Marketing Elimination Total
----------------------------------------------
Revenue
Gross production
revenue $ 305,531 $ - - $ 305,531
Royalties (72,869) - - (72,869)
Product sales and
service revenue - 197,148 (24,957) 172,191
Other revenue 1,476 - - 1,476
----------------------------------------------
234,138 197,148 (24,957) 406,329
----------------------------------------------

Expenses
Cost of goods sold - 178,104 (24,957) 153,147
Production, operating,
and maintenance 76,396 7,644 - 84,040
Transportation 5,447 - - 5,447
Cash general and
administrative 14,289 1,076 - 15,365
Non-cash general and
administrative 1,223 82 - 1,305
Foreign exchange 180 180
Management
internalization 18,592 - - 18,592
----------------------------------------------
116,127 186,906 (24,957) 278,076

Earnings before interest
taxes, depletion,
depreciation and
accretion 118,011 10,242 - 128,253

Interest on long-term
debt and convertible
debentures 15,709 1,365 - 17,074
Accretion and
amortization on
convertible debentures 2,405 209 2,614
Depletion, depreciation
and accretion 136,066 2,206 - 138,272
Capital taxes 3,177 155 - 3,332
Future income tax
recovery (Note 15) (55,074) (1,404) - (56,478)
----------------------------------------------
102,283 2,531 - 104,814

Net income (loss) for
the period $ 15,728 $ 7,711 - $ 23,439
----------------------------------------------

Capital Expenditures
Acquisition of
Redwater $ - $ 298,638 $ - $ 298,638
Property, plant and
equipment $ 31,628 $ - $ - $ 31,628
Selected balance
sheet items
Working capital
Accounts receivable $ 47,691 $ 76,106 $ (4,907) $ 118,890
Petroleum product
inventory $ - $ 24,206 $ - $ 24,206
Accounts payable $ 52,146 $ 74,593 $ (4,907) $ 121,832
Long-term debt $ 243,334 $ 113,239 $ - $ 356,573


19. Subsequent event

On February 9, 2005 the Trust announced it's intention to issue 8.4
million Trust units at $12.00 per unit for proceeds of $100.8 million
($95.8 million net of issue costs) and $100 million (($96.0 million net
of issue costs) of 6.5 percent convertible debentures pursuant to a
final prospectus dated February 18, 2005. The bought deal financing
closed March 1, 2005. On March 2, 2005, the proceeds were used to pay
for the C$96 million (US$75 million) Nautilus corporate acquisition by
Provident Energy's U.S. subsidiary Breitburn Energy L.P. The remainder
of the funds were used to pay down Provident Energy's long-term debt.



Provident Energy Ltd


Thomas w. Buchanan
Chief Executive Officer


-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Provident Energy Trust
    Jennifer Pierce
    Senior Manager Investor Relations and Communications
    (403) 231-6736
    Email: info@providentenergy.com
    Website: www.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) 261-6696 (FAX)