Management's Discussion and Analysis

The following analysis provides a detailed explanation of Provident's operating results for the three months ended March 31, 2004 compared to the three months ended March 31, 2003 and should be read in conjunction with the consolidated financial statements of Provident.

This disclosure contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Provident's control, including the impact of general economic conditions in Canada and the United States; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; increased competition; the lack of availability of qualified personnel or management; 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 occur, or if any of them do so, what benefits, including the amounts of proceeds, that Provident will derive therefrom. 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 two key business segments: crude oil and natural gas production and exploitation (OGP) and Midstream Services and Marketing (Midstream). Provident's OGP business unit produces crude oil and natural gas from five core areas in the western Canadian sedimentary basin while 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 OGP 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.

Provident Energy Trust 2004 Q1 [1]

Consolidated cash flow from operations and cash distributions

	Three months ended
	March 31,
	2004	2003
Revenue, Cash Flow and Distributions
Revenue (net of royalties and non-hedging derivative instruments)	234,947	66,710
Cash flow from Operations	39,212	41,961
Per weighted average unit - basic1	0.45	0.69
Per weighted average unit - diluted1	0.45	0.69
Interest on convertible debentures	(2,943)	(1,589)
Adjusted cash flow	36,269	40,372
Declared distributions	31,036	33,091
Per Unit2	0.36	0.60
Percent of cash flow distributed	79%	79%
Percent of adjusted cash flow distributed	86%	82%

1 includes exchangeable shares
² excludes exchangeable shares

Cash flow from operations ("cash flow") decreased 7 percent or $2.7 million in the first quarter of 2004 to $39.2 million as compared to the first quarter of 2003 total of $42.1 million. OGP generated $28.8 million of cash flow in the first quarter of 2004 compared to $42.0 million in the first quarter of 2003 while Midstream generated $10.4 million in cash flow in the first quarter of 2004 with no comparable figure for 2003.

The decrease in OGP cash flow is attributable to a 15 percent production decline combined with a decrease in the realized commodity prices as well as a higher weighting of heavy oil in Provident's production mix in the first quarter of 2004 compared to the first quarter of 2003.

The 15 percent decrease in production was due to natural production declines offset by development volume additions. The decrease in the realized commodity price was primarily associated with the lower natural gas prices in tandem with the appreciated value of the Canadian dollar against the US dollar in the first quarter of 2004 compared to the first quarter of 2003. Quarter over quarter there was a 13 percent appreciation in the value of the Canadian dollar against the US dollar. For commodity prices denominated in US dollars the appreciation of the Canadian dollar resulted in lower realized prices for Provident. Provident had a slightly higher percentage of heavy oil in its production mix in the first quarter of 2004 when compared to the first quarter of 2003. Prices for heavy oil are lower than for light or medium blends of crude oil. In 2003 natural production declines were primarily offset by a heavy oil drilling program. Heavy oil accounted for 27 percent of first quarter 2004 production compared to 22 percent in the first quarter of 2003.

Cash flow per unit decreased 35 percent to $0.45 from $0.69 in the first quarter of 2004 as compared to the first quarter of 2003. The opportunity cost associated with the Commodity Price Risk Management Program was $0.11 per unit in the first quarter of 2004 compared to an opportunity cost of $0.37 in the first quarter of 2003.

Management uses cash flow (before changes in non-cash working capital) to analyze operating performance. Cash flow 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. Cash flow as

Provident Energy Trust 2004 Q1 [2]

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.

Adjusted cash flow

Provident uses the term adjusted cash flow to refer to cash flow from operations net of the interest paid on the subordinated convertible debentures. Management reviews adjusted cash flow in setting distributions and historically has paid out the majority of its adjusted cash flow as distributions to unitholders. Provident has historically maintained a high payout ratio of adjusted cash flow as it has funded its annual capital program primarily through participation in its Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan program and minor property dispositions.

Distributions

The following table summarizes distributions paid or declared by the Trust since inception:
		Distribution Amount
Record Date	Payment Date	(Cdn$)	(US$)
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
Q1 2004 Cash Distributions paid as declared		$0.36	$0.27
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 March 31, 2004 - Distributions paid as declared		$6.99	$4.67

*exchange rate based on the Bank of Canada noon rate on the payment date.

Net loss

		Three months ended
		March 31,
(000s except per unit data)		2004		2003
Net loss	$	(2,251)	$	(8,743)
Per weighted average unit	$	(0.06)	$	(0.17)
- basic(1)
Per weighted average unit	$	(0.06)	$	(0.17)
- diluted(2)

(1) Based on weighted average number of trust units and trust units that would be issued upon conversion of exchangeable shares. Net loss 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.

Provident Energy Trust 2004 Q1 [3]

The net loss for the first quarter of 2004 is due to the implementation of CICA Accounting Guideline 13, "Hedging relationships." Under accounting guideline 13, hedging transactions must be documented and it must be demonstrated that the hedges are sufficiently effective to continue hedge accounting for positions hedged with derivatives. Provident did not apply hedge accounting to the Commodity Price Risk Management Program and therefore has marked to market the outstanding derivatives as of March 31, 2004. This resulted in a non-cash charge of $15.5 million in the first quarter of 2004. In addition, under accounting guideline 13, Provident's December 31, 2003 mark to market opportunity cost position of $25.2 million was set up as a deferred derivative loss and will be amortized as a non-cash expense over the life of those derivatives. Amortization of this amount resulted in a non-cash charge of $6.6 million in the first quarter of 2004. The combined net non-cash pre-tax charge for the quarter attributed to accounting guideline 13 was $22.0 million. On an after tax basis the impact was $14.1 million. 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.

The OGP business segment contributed $28.8 million of cash flow, $30.7 million of income before DD&A, taxes and non-cash charges to income, and had a net loss of $14.5 million. The Midstream business unit contributed $10.4 million of cash flow, $11.7 million of income before DD&A, taxes and non-cash charges to income, and had net income of $4.4 million.

The first quarter 2003 net loss was primarily associated with $18.4 million non-cash expense associated with the management internalization. Further, the 2003 comparative figures for the net loss have been restated for the retroactive application of the Asset Retirement Obligation accounting standard.

Taxes

		Three months ended
		March 31,
		2004		2003
Capital taxes	$	1,005	$	1,210
Future income taxes recovery	$	(14,549)	$	(2,674)

The first quarter 2004 future income tax recovery of $10.5 million was in part due to the Alberta corporate income tax rate dropping from 12.5 percent to 11.5 percent.

Capital taxes include the Saskatchewan Resource surcharge and federal and provincial large corporation taxes. Comparative figures for future income taxes (recovery) have been restated due to the retroactive application of the new Asset Retirement Obligation accounting standard.

Interest expense

		Three months ended
		March 31,
		2004		2003
Interest on long-term debt	$	2,144	$	2,269
Weighted-average interest rate		4.0%		4.2%

Interest expense decreased by 6 percent in the first quarter of 2004 as compared to the first quarter of 2003. This is primarily due to the issue of 4.5 million units on February 4, 2004 for net proceeds of $47.9 million. Proceeds of the issuance of these units were applied against long-term debt and, at March 31, 2004 Provident's long-term debt of $178.8 million was 5 percent lower than March 31, 2003.

Provident Energy Trust 2004 Q1 [4]

Financial Instruments

Commodity Price Risk Management Program

Provident's Commodity Price Risk Management Program has been in place since the inception of the Trust to help manage the volatility in Provident's oil and natural gas prices and to assist with stabilizing cash flow and distributions per unit. Provident uses a combination of forward sales contracts, physical hedges on both wellhead prices and heavy oil differentials, financial hedging on WTI crude oil and AECO natural gas prices and Cdn/US exchange rate hedges.

For the first quarter of 2004 the program recorded an opportunity cost of $9.4 million on crude oil ($8.23 per barrel) and an opportunity cost of $0.5 million on natural gas ($0.08 per mcf) compared to an opportunity cost of $11.7 million on crude oil ($9.60 per barrel) and an opportunity cost of $10.9 million on natural gas ($1.45 per mcf) in the first quarter of 2003. In addition, the Midstream business unit realized a gain of $0.2 million on propane, ethane and foreign exchange hedging activities with no comparative for 2003. On a per unit basis opportunity costs were $0.11 in the first quarter of 2004 compared to $0.37 in the first quarter of 2003.

At March 31, 2004 the mark to market value of open contracts was in a loss position of $40.6 million based on commodity prices prevailing at that date. A table summarizing Provident's aggregate position under the Commodity Price Risk Management Program as at March 31, 2004 is available on Provident's website at www.providentenergy.com.

Liquidity and Capital Resources

		March 31,		December 31,
		2004		2003
Long-term debt	$	178,800	$	236,500
Working capital (surplus)/deficit		15,343		(18,552)
Net debt		194,143		217,948
Equity (at book value)		695,813		679,228
Total capitalization at book value	$	889,956	$	897,176
Net debt as a percentage of total book		22%		24%
value capitalization

Bank debt and working capital

As at March 31, 2004 Provident had drawn on 58 percent of its $310.0 million term credit facility as compared to 80 percent drawn as of December 31, 2003. The decrease in the percentage drawn was due to the issue of 4.5 million units for net proceeds of $47.9 million on February 4, 2004. The proceeds for the issuance of these units has initially been applied to long-term debt.

At March 31, 2004 Provident had letters of credit guaranteeing Provident's performance under certain commercial contracts that totaled $15.1 million, marginally increasing bank line utilization to 63 percent. The

Provident Energy Trust 2004 Q1 [5]

guarantees are associated with the midstream business unit. At December 31, 2003 Provident's guarantees totaled $12.3 million.

Provident's working capital decreased by $33.9 million as at March 31, 2004. $22.0 million of the decrease was due to the implementation of accounting guideline 13, "Hedging Relationships" (see changes in accounting policy in this MD&A), $10.2 million was due to the decrease in petroleum product inventory, while $1.7 million was due to changes in miscellaneous working capital accounts.

Convertible subordinated debentures

	Three months ended March 31,
		2004			2003
	Number		Amount	Number		Amount
10.5% convertible debentures	of Units		(000s)	of Units		(000s)
Principal balance at beginning of period		$	49,935		$	64,285
Debenture conversions in the period	2,336		(25)	177,986		(1,905)
Principal balance at end of period			49,910			62,380
Convertible debenture issue costs			(2,333)			(2,916)
Net convertible debenture balance at end of period		$	47,577		$	59,464
Interest on 10.5% convertible debentures		$	1,307		$	1,589
	Number		Amount	Number		Amount
8.75% convertible debentures	of Units		(000s)	of Units		(000s)
Principal balance at beginning of period		$	75,000		$	-
Debenture conversions in the period	-		-		-	-
Principal balance at end of period			75,000			-
Convertible debenture issue costs			(3,200)			-
Net convertible debenture balance at end of period		$	71,800		$	-
Interest on 8.75% convertible debentures		$	1,636		$	-
	Number		Amount	Number		Amount
Total convertible debentures	of Units		(000s)	of Units		(000s)
Principal balance at beginning of period		$	124,935		$	64,285
Debenture conversions in the period	2,336		(25)	177,986		(1,905)
Principal balance at end of period			124,910			62,380
Convertible debenture issue costs			(5,533)			(2,916)
Net convertible debenture balance at end of period		$	119,377		$	59,464
Total interest on convertible debentures		$	2,943		$	1,589

The Trust's debentures net of issue costs are currently classified in Unitholders' Equity as the principal amount of the debentures can be settled with either trust units or cash at the time of maturity. Interest on the Debentures is included in Unitholders' Equity as accumulated interest on convertible debentures.

Provident Energy Trust 2004 Q1 [6]

Trust units

In the first quarter of 2004 the Trust issued 0.3 million units on conversion of exchangeable shares to units (conversion amount $2.1 million) (first quarter of 2003 - 3.1 million units with a conversion amount of $31.3 million), 0.002 million units on conversion of convertible debentures (conversion amount $0.025 million) (first quarter of 2003 - 0.2 million units with a conversion amount of $1.9 million) and 0.4 million units were issued or are to be issued resulting from Provident's DRIP program (proceeds of $4.6 million) (first quarter of 2003 - 0.7 million units with proceeds of $7.5 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 will be used to finance the 2004 capital budget.

Capital expenditures and funding

		Three Months Ended
		March 31,
		2004		2003
Capital Expenditures and Funding
Capital Expenditures
Capital expenditures and site restoration	$	(12,071)	$	(7,210)
Property acquisitions		(4,718)		-
Corporate acquisitions		-		(164)
Property dispositions		6,409		1,788
Net capital expenditures	$	(10,380)	$	(5,586)
Funded By
Adjusted cash flow net of declared distributions		5,233		7,281
Issue of trust units, net of cost; excluding DRIP		48,631		600
DRIP proceeds		4,604		7,500
Change in working capital		9,612		(11,095)
Increase (decrease) in long term bank debt		(57,700)		1,300
	$	10,380	$	5,586

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

Provident Energy Trust 2004 Q1 [7]

Asset retirement obligation

	For the three months ended March 31,
	2004	2003
Carrying amount, beginning of period	$   33,182	$   32,645
Increase in liabilities during the period	329	130
Settlement of liabilities during the period	(1,068)	(143)
Accretion expense	580	543
Carrying amount, end of period	$   33,023	$33,175

Asset retirement obligation (ARO) decreased by $0.2 million to $33.0 million during the first quarter of 2004. The decrease in the ARO balance in the quarter is primarily associated with the disposition of the Westward Ho area.

The Trust's asset retirement obligation is based on the Trust's net ownership in wells and facilities and management's estimate of the costs to abandon and reclaim those wells and facilities as well as an estimate of the future timing of the costs to be incurred. Midstream assets, including the Redwater facility, the Younger Plant and the liquids gathering system have been excluded from the asset retirement obligation as retirement obligations associated with these assets have indeterminate settlement dates.

The total undiscounted amount of future cash flows required to settle asset retirement obligations is estimated to be $99.0 million. Payments to settle asset retirement obligations occur over the operating lives of the assets estimated to be from zero to 20 years. Estimated cash flows have been discounted at the Trust's credit-adjusted risk free rate of 7 percent and an inflation rate of 2 percent.

Non-cash general and administrative

Non-cash general and administrative includes expenses or recoveries associated with Provident's unit option plan. Provident recorded a recovery of $0.4 million in the first quarter of 2004 (2003 - nil).

OGP Segment Review

Crude oil price

The following prices are net of transportation expense.

		Three months ended
		March 31,
		2004		2003	% change
Oil per barrel
WTI (US$)	$	35.16	$	33.80	4
Exchange rate (from US$ to Cdn$)	$	1.32	$	1.51	(13)
WTI expressed in Cdn$	$	46.41	$	51.04	(9)
Corporate realized crude oil and natural gas	$	32.98	$	38.61	(15)
liquids price before hedging (Cdn$)
Corporate realized light/medium oil price	$	39.00	$	43.64	(11)
before hedging (Cdn$)
Corporate realized heavy oil price before	$	26.84	$	31.63	(15)
hedging (Cdn$)
Corporate realized natural gas liquids price	$	37.03	$	45.13	(18)
before hedging (Cdn$)

Provident Energy Trust 2004 Q1 [8]

Provident's pre-hedged realized oil and natural gas liquids price decreased 15 percent to $32.98 in the first quarter of 2004 as compared to the first quarter of 2003. Two key factors lead to decrease Provident's pre-hedged realized oil and natural gas liquids price. First, the 13 percent strengthening in the value of the Canadian dollar versus the US dollar in the first quarter of 2004 compared to the first quarter of 2003, eroded Provident's pre-hedged price. Secondly, lower priced heavy oil, as a percentage of total oil and natural gas liquids production, increased 5 percent to 48 percent in the first quarter of 2004 when compared to the first quarter of 2003.

Natural gas price

The following prices are net of transportation expense.

		Three months ended
		March 31,
		2004		2003	% change
AECO (Cdn$)	$	6.60	$	7.61	(13)
Gas revenue per mcf (1)(Cdn$)	$	6.40	$	7.94	(19)
(1) Excluding the effects of the commodity price risk management program

Provident's realized gas price excluding hedges was off 19 percent in the first quarter of 2004 compared to the very high price environment that existed in the first quarter of 2003.

	Three months ended
	March 31,
	2004	2003	% change
Daily production
Crude oil - Light/Medium (bpd)	5,965	7,285	(18)
- Heavy (bpd)	6,588	6,245	5
Natural gas liquids (bpd)	1,130	1,085	4
Natural gas (mcfd)	63,859	83,924	(24)
Oil equivalent (boed) (1)	24,326	28,602	(15)
(1) Provident reports equivalent production converting natural gas to oil on a 6:1 basis.

The first quarter of 2004 daily production mix was 44 percent natural gas, 27 percent conventional heavy oil and 29 percent medium/light crude oil and natural gas liquids. This compares to 49 percent natural gas, 22 percent conventional heavy oil and 29 percent medium/light crude oil and natural gas liquids in the first quarter of 2003. Any single property within Provident's portfolio does not exceed 10 percent of daily production.

Provident Energy Trust 2004 Q1 [9]

Revenue and royalties

		Three months ended
		March 31,
		2004		2003	% change
Oil
Revenue	$	38,524	$	46,828	(18)
Cash hedging		(9,396)		(11,685)	(20)
Royalties (net of ARTC)		(7,272)		(8,665)	(16)
Net revenue	$	21,856	$	26,478	(17)
Net revenue (per barrel)	$	19.13	$	21.74	(14)
Royalties as a percentage of revenue		18.9%		18.5%	3
Natural gas
Revenue	$	37,620	$	60,572	(38)
Cash hedging		(445)		(10,917)	(96)
Amortization of deferred hedging		-		(245)	-
Royalties (net of ARTC)		(6,971)		(13,651)	(49)
Net revenue	$	30,204	$	35,759	(16)
Net revenue (per mcf)	$	5.20	$	4.73	10
Royalties as a percentage of revenue		18.5%		22.5%	(18)
Natural gas liquids
Revenue	$	3,808	$	4,406	(14)
Royalties		(1,002)		(1,616)	(38)
Net revenue	$	2,806	$	2,990	(6)
Net revenue (per barrel)	$	27.29	$	30.62	(11)
Royalties as a percentage of revenue		26.3%		36.7%	(28)
Total
Revenue	$	79,952	$	111,806	(28)
Cash hedging		(9,841)		(22,602)	(56)
Amortization of deferred hedging		-		(245)	-
Royalties (net of ARTC)		(15,245)		(23,932)	(36)
Net revenue	$	54,866	$	65,027	(16)
Net revenue per boe	$	24.78	$	25.26	(3)
Royalties as a percentage of revenue		19.1%		21.4%	(10)

Quarter over quarter, oil, natural gas, and natural gas liquids revenue has decreased by 28 percent. The decrease in revenue is made up of three key elements. First, production decreased 15 percent in the first quarter of 2004 when compared to the first quarter of 2003. Second, Provident's pre-hedged realized price for oil, natural gas and natural gas liquids decreased 17 percent in the first quarter of 2004 when compared to the first quarter of 2003. The decrease in Provident's pre-hedged realized price is primarily associated with the 13 percent appreciation of the Canadian dollar compared to the US dollar but is also due to weaker commodity prices for natural gas as well as a 5 percent increase in heavy oil production as a percentage of Provident's oil and natural gas liquids production.

Production expenses

		Three months ended
		March 31,
		2004		2003	% change
Production expenses	$	18,504	$	17,484	6
Production expenses (per boe)	$	8.36	$	6.79	23

Production expenses, expressed on a boe basis, increased 23 percent in the first quarter of 2004 compared to the same period in 2003. This increase reflects declining production volumes bearing the fixed cost

Provident Energy Trust 2004 Q1 [10]

component of operating cost over fewer barrels of oil equivalent production. Further, higher costs for electricity, propane, processing fees and equalization costs have trended higher in recent quarters driven by high commodity prices and increased servicing and workover costs.

In the current commodity price environment of WTI in excess of US$30 per barrel and AECO above CDN$6.00/GJ, the increased electricity costs and processing charges will drive Provident's operating costs to the $8.00 to $8.50 per barrel range.

General and administrative

		Three months ended
		March 31,
		2004		2003	%change
Cash general and administrative	$	4,386	$	2,918	50
Cash general and administrative per boe	$	1.98	$	1.13	75

General and administrative expenses increased 50 percent in the first quarter of 2004 when compared to the first quarter of 2003 due to additional staff and increased rent. The increase in the barrel of oil equivalent rate has also been affected by the 15 percent quarter over quarter production decrease.

Operating netback

		Three months ended
		March 31,
		2004		2003	% change
Netback per boe
Gross production revenue	$	35.88	$	43.44	(17)
Cash hedging		(4.45)		(8.78)	(49)
Realized revenue		31.43		34.66	(9)
Royalties (net of ARTC)		(6.89)		(9.30)	(26)
Transportation costs		(0.56)		(0.42)	33
Operating costs		(8.36)		(6.79)	23
	$	15.62	$	18.15	(14)

At $15.62 the first quarter 2004 operating netback was 14 percent lower than the $18.15 realized in the first quarter of 2003. The decrease in the netback is due to lower realized commodity prices and higher operating costs offset by lower opportunity costs on hedging activities and decreased royalty costs.

Depletion, depreciation and accretion (DD&A)

		Three months ended
		March 31,
Canadian dollars (000s except per unit data)		2004		2003
DD&A	$	32,153	$	34,783
DD&A per boe	$	14.53	$	13.52

DD&A includes accretion expense associated with asset retirement obligation of $0.6 million in the first quarter of 2004 (first quarter of 2003 - $0.5 million).

Provident Energy Trust 2004 Q1 [11]

Capital expenditures

		Three months ended
		March 31,
Canadian dollars (000s)		2004		2003
Lloydminster	$	500	$	3,118
West central and southern Alberta		2,190		1,847
Southeast and southwest Saskatchewan		7,750		1,120
Office and other		540		482
Total additions	$	10,980	$	6,567
Property acquisitions	$	4,718	$	-
Dispositions	$	6,409	$	1,788

Provident's capital expenditures are primarily 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 directs proceeds from the DRIP program, along with the proceeds from asset dispositions, towards the capital expenditure budget.

Provident spent $11.0 million in the first quarter of 2004 of which $0.5 million was spent in the Lloydminster core area on re-completions, equipping and seismic activities. $2.2 million was spent in the west central and southern Alberta core areas on non-operated drilling activities combined with several re-completions, and facility upgrades. $7.8 million was spent in southeast and southwest Saskatchewan primarily for the acquisition of mineral rights.

Provident also executed several property acquisitions in the first quarter of 2004. Through these purchases Provident acquired some production as well as additional mineral rights in both the Lloydminster and southern Alberta core areas.

Provident incurred $6.6 million of capital expenditures in the first quarter of 2003 primarily associated with a drilling program in the Lloydminster core area.

In the quarter Provident received proceeds of $6.4 million from the disposition of properties that management believed did not fit within the risk profile for future development at Provident. The proceeds of the disposition will be used to fund a portion of Provident's 2004 capital program.

Midstream Services and Marketing Review

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.

Provident Energy Trust 2004 Q1 [12]

• 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 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 services

Provident's midstream services offers 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, processing, fractionation, storage and distribution of their NGL barrels and are responsible for the marketing of their product.
   

• Fixed margin processing: This service involves NGL owners delivering their product to Provident with Provident taking title and paying the NGL owner an amount that is the difference between a delivery price of raw NGLs that is discounted to postings and the posted price in that month for the finished products (this is the "fixed margin"). The discounted price that Provident purchases the product for covers the costs of transportation, fractionation, storage, marketing and distribution of the NGLs.
   

• Storage: NGL owners pay fees to store their NGLs.
   

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

The contracts

At the Redwater facility, approximately 75% of the available capacity is contracted through fee-for-service with major oil and natural gas producers and petrochemical businesses. As a result of these contracts, approximately 68% of Redwater's system volume 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. During the quarter throughput averaged 58,640 bpd. While throughput at Redwater averaged less than 63,000 bpd, Provident was able to optimize existing capacity and contractual arrangements to achieve its financial objectives.

Revenues

First quarter of 2004 product sales and services revenues of $161.2 million include T&F processing, fixed margin processing and revenues generated through storage and distribution services. The majority of NGL

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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 $139.6 million for the quarter relates to NGL product sales revenue included in the product sales and services revenue, where Provident has purchased the natural gas liquids. 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 existing North American facilities of this type. First quarter 2004 operating costs of $9.0 million were representative of normal operations for the quarter without any major turnarounds or operating difficulties. General and administrative expenses of $0.9 million, interest of $1.1 million, and depreciation of $2.3 million for the quarter are estimated by management to also be representative of normal operations for a quarter.

Crude oil marketing

In the first quarter of 2004 $33.2 million revenue was generated from marketing other producers' crude oil. Management estimates that marketing of third party volumes, combined with certain Provident crude oil volumes, will provide better producer netbacks than can be achieved through third party marketers.

Critical Accounting Policies

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.

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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 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

The new Canadian Institute of Chartered Accountants ("CICA") standard for Asset Retirement Obligations changes the method of accounting for certain site restoration costs. Under the new standard, the fair value of asset retirement obligations are recorded as liabilities 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 financials results.

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 $25.2 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 $6.6 million loss before taxes and was recorded in amortization of deferred charges on the Statement of Operations and Accumulated Loss.

At March 31, 2004 the Trust recorded a non-hedging derivative instrument payable of $40.6 million ($35.4 million short-term and $5.2 million long-term), that 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 $15.4 million on the Statement of Operations and Accumulated Loss, that being the difference between January 1, 2004 mark to market loss position of $25.2 million on non-hedging derivative instruments and the March 31, 2004 loss position of $40.6 million on non-hedging derivative instruments.

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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.

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;

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• 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.

Risks associated with the level of foreign ownership

Generally, a trust cannot qualify as a "mutual fund trust" for the purposes of the Tax Act if it is established or is being maintained primarily for the benefit of non-residents. Although not without uncertainty, this is generally accepted to exist in most situations where Non-Resident holders own significantly in excess of 50% of the aggregate number of Trust Units issued and outstanding. However, there is currently an exception to the non-resident ownership restriction where not more than 10% of the trust's property has at any time consisted of "taxable Canadian property". Prior to the March 2004 Canadian Federal Budget (the "Budget"), Canadian resource property, including a resource royalty, was not "taxable Canadian property" for this purpose, and therefore a number of resource royalty trusts, including the Trust, were not required to restrict non-resident ownership of their units. Under the Federal Canadian Budget proposals, the definition of "taxable Canadian property" for this purpose will be amended so as to include Canadian resource property, and therefore resource royalty trusts, including the Trust, will be required to restrict non-resident ownership of their units prior to January 1, 2007.

Unit trading activity

The following table summarizes the unit trading activity of the Provident units for the three months ended March 31, 2004 on both the Toronto Stock Exchange and the American Stock Exchange:

	First Quarter
TSE - PVE.UN (Cdn$)
High	$	11.55
Low	$	9.21
Close	$	10.76
Volume (000s)		13,156
AMEX - PVX (US$)
High	$	9.06
Low	$	7.59
Close	$	8.24
Volume (000s)		36,172

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Quarterly table

		2004
		First
($000s except per unit amounts)		Quarter
Financial - consolidated
Revenue	$	234,947
Cash flow	$	39,212
Net income	$	(2,251)
Unitholder distributions	$	31,036
Distributions per unit	$	0.36
Oil and gas production
Cash revenue	$	54,865
Earnings before interest, DD&A, taxes
and other non-cash items	$	30,741
Cash flow	$	28,822
Net income	$	(6,994)
Midstream services and marketing
Cash revenue	$	233,031
Earnings before interest, DD&A and
taxes	$	11,682
Cash flow	$	10,452
Net income	$	4,743
Operating
Oil and gas production
Light/medium oil (bpd)		5,965
Heavy oil (bpd)		6,588
Natural gas liquids (bpd)		1,130
Natural gas (mcfd)		63,859
Oil equivalent (boed)		24,326
Midstream services and marketing
Redwater throughput (bpd)		58,640
(Cdn $)
Average selling price net of transportation expense
Light/medium oil per bbl
(before hedges)	$	39.00
Light/medium oil per bbl
(including hedges)	$	26.15
Heavy oil per bbl
(before hedges)	$	26.84
Heavy oil per bbl
(including hedges)	$	22.80
Natural gas liquids per barrel	$	37.03
Natural gas per mcf
(before hedges)	$	6.40
Natural gas per mcf
(including hedges)	$	6.32

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Quarterly table

				2003
		First	Second	Third	Fourth	YTD
($000s except per unit amounts)		Quarter	Quarter	Quarter	Quarter	Total
Financial - consolidated
Revenue	$	66,710 $	57,520 $	67,622 $	214,297 $	406,149
Cash flow	$	41,961 $	31,571 $	28,866 $	33,308 $	135,706
Net income	$	(8,743) $	23,073 $	(2,003) $	21,067 $	33,394
Unitholder distributions	$	33,091 $	35,528 $	28,969 $	32,023 $	129,611
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 $	54,468 $	233,958
Earnings before interest, DD&A and
taxes	$	26,845 $	33,989 $	31,517 $	25,660 $	118,011
Cash flow	$	41,961 $	31,571 $	28,785 $	24,385 $	126,702
Net income	$	(8,743) $	23,073 $	(2,003) $	12,947 $	25,274
Midstream services and marketing
Cash revenue	$	- $	- $	23,713 $	173,435 $	197,148
Earnings before interest, DD&A and
taxes	$	- $	- $	81 $	10,243 $	10,324
Cash flow	$	- $	- $	81 $	8,923 $	9,004
Net income	$	- $	- $	81 $	8,039 $	8,120
Operating
Oil and gas production
Light/medium oil (bpd)		7,825	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 $)
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

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