Provident Energy Announces First Quarter Results.CALGARY, Alberta -- Provident Energy Trust (TSX:PVE.UN) (AMEX:PVX): All values are in Canadian dollars and conversions of natural gas volumes to barrels of oil equivalent (boe) are at 6:1 unless otherwise indicated. First quarter 2005 highlights - Provident's U.S. subsidiary BreitBurn Energy completed the $95.8 million acquisition of Wyoming-based Nautilus Resources adding 2,300 boed of production and 20.1 million barrels of Proved Plus Probable reserves at a cost of $4.77 per barrel - Provident closed a bought deal financing raising net proceeds of $191.8 million - Provident generated $64.1 million ($0.43/unit) in cash flow from operations - Provident declared distributions of $51.7 million ($0.36/unit) representing a payout ratio of 81 percent of cash flow from operations Provident Energy Trust (Provident) (TSX-PVE.UN; AMEX-PVX) reported first quarter 2005 cash flow from operations of $64.1 million ($0.43/unit) compared to $36.3 million ($0.41/unit) generated in the first quarter of 2004, an increase of 77 percent. Distributions declared in the quarter totaled $51.7 million ($0.36/unit) compared to $31.0 million ($0.36/unit) in 2004. For the first quarter 2005, Provident's payout ratio of cash flow from operations was 81 percent compared to 86 percent in the same period of 2004. Provident adopted and retroactively applied the classification of convertible debentures as debt and netted the interest expense from cash flow and income for the compared 2004 quarter. Consequently, adjusted cash flow is no longer relevant. "Provident experienced a strong start to 2005. Operations within our oil and gas production and midstream services business units were solid and our financial results for the quarter were consistent with expectations," said Provident Chief Executive Officer Tom Buchanan. "We continue to pursue our balanced portfolio business strategy and executed several actions during the first quarter that support our objectives to increase cash flow per unit, enhance the sustainability of the trust, establish new platforms for growth, and be disciplined in the management of our financial resources." On March 2, 2005 Provident's U.S. subsidiary BreitBurn Energy closed the $95.8 million (US$77.6 million) acquisition of Nautilus Resources (Nautilus), a private company based in Wyoming. The newly acquired operations are located in the Big Horn and Wind River Basins. Current production is approximately 2,300 boed consisting of 99 percent crude oil and one percent natural gas. The acquisition included 10.6 million barrels of Proved Producing reserves, 17.1 million barrels of Total Proved reserves and 20.1 million barrels of Proved Plus Probable reserves based on the January 1, 2005 reserve report completed by independent engineers Netherland, Sewell & Associates in accordance with NI 51-101. The respective reserve life indices of the reserves are 12.6 years, 20.4 years and 23.9 years. Provident acquired Nautilus at a cost of $41,652 per flowing barrel, $ 9.04 per barrel of Proved Producing reserves, $5.61 per barrel of Total Proved reserves, and $4.77 per barrel of Proved Plus Probable reserves. Additionally during the first quarter, Provident closed a bought deal financing, issuing 8.4 million trust units at a price of $12.00 per unit and $100 million of 6.5 percent, seven and half year convertible unsecured subordinated debentures that mature on August 31, 2012 for net proceeds of approximately $191.8 million. The net proceeds of the financing were used to fund the acquisition of Nautilus and to repay a portion of Provident's bank debt. Business Unit Results "During the first quarter, Midstream Services continued to post very strong results and exceed our original EBITDA estimates due to enhanced marketing activities and increased revenues from our NGL storage and distribution activities," said Provident President Randy Findlay. "Canada and U.S. Oil and Gas Production's (OGP OGP - International Association of Oil & Gas Producers (UK & Belgium) OGP - Office of Global Programs (US National Oceanic and Atmospheric Administration) OGP - Office of Governmentwide Policy (US) OGP - Open Guilty Plea (court) OGP - Optical Gaging Products, Inc.) operations remain on track for the year despite delays experienced in our drilling programs caused by an early spring break up in Canada and record rainfall in the Los Angeles area. Drilling activities will ramp up significantly in the second quarter particularly at Provident's Lloydminster and Southwest Saskatchewan fields in Canada and West Pico area in Los Angeles." Midstream Services Provident's Midstream Services 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. Midstream Services assets comprise the most modern and lowest-cost-NGL processing system of its kind in western Canada and include 100-percent ownership of the Redwater NGL Fractionation Facility; 100-percent ownership of the proprietary Liquids Gathering System; and 43.3-percent ownership of the Younger Extraction Plant. For the first quarter of 2005, Provident's Midstream Services business unit generated $16.4 million in EBITDA, a 34 percent increase over the year ago quarter. Cash flow from operations increased 54 percent from the first quarter 2004 to $15.2 million. The increase in EBITDA and cash flow was due to efficient operations, enhance marketing activities and increased revenue from NGL storage and distribution services. Throughput at the Redwater fractionation facility averaged 58,504 bpd compared to 58,640 bpd for first quarter 2004. For 2005, reflecting the strength of its marketing activities, Provident is revising its annual EBITDA guidance from $40 million to $42 to $46 million. U.S. Oil and Gas Production (USOGP) 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 (BreitBurn) operates 100 percent of the production. Provident's interest in BreitBurn is approximately 96 percent. On March 2, 2005 Provident closed the acquisition of Nautilus by BreitBurn. Nautilus properties include eight fields in the Big Horn and Wind River Basins with an average 99.4 percent working interest and 85.8 percent revenue interest after royalties. A senior U.S. oil and gas company previously owned four of the main fields, representing 84 percent of reserves. The acquired properties have been on production for 60 to 90 years and the average annual decline rate is six percent. There are currently 150 active producing wells and 25 active water injection wells. "The Nautilus acquisition provides Provident with another vehicle to expand the trust's production base in the U.S. with quality, mature, long-life assets in fields with significant original oil in place," said Provident President Randy Findlay. "The BreitBurn team has experience in the Wyoming basins through their discovery and exploitation of their Lost Dome field which is located near the Nautilus assets. Given their knowledge of the basins and technical expertise, the BreitBurn team has identified opportunities that should increase production and enhance the ultimate recovery of oil from the fields in Big Horn and Wind River." In the first quarter of 2005, USOGP generated $11.4 million of cash flow from operations and production averaged 5,992 boed. BreitBurn was acquired June 15, 2004 and therefore there are no first quarter comparative figures for 2004. Production over the period was weighted 94 percent light/medium crude oil and six percent natural gas. USOGP production increased 1,755 boed in the first quarter of 2005 when compared to production during the period June 15 to December 31, 2004. The increase is primarily attributable to the first full quarter of the October 4, 2004 acquired Orcutt properties that added 1,344 boed combined with one month of the Nautilus properties production that added 2,225 boed. The USOGP exit production rate for the first quarter of 2005 is approximately 7,400 boed. Operating costs were $13.77/boe during the first quarter compared to $15.16/boe during the fourth quarter of 2004. For the remainder of 2005, operating costs are expected to remain in the $13.00 to $13.50 per boe range assuming an exchange rate of Cdn 1.25 / U.S. 1.00. Operating netbacks Operating Netback A measure of oil and gas sales net of royalties, production and transportation expenses. This is a non-GAAP measure used specifically in the oil and gas industry as a benchmark to compare performance between time periods, operations and competitors.Notes: The measure is generally calculated based on the oil or gas selling metric, such as per barrel in the case of oil. in the first quarter 2005 remain strong, driven by
high commodity prices partially offset by increasing operating and
opportunity costs.During the first quarter, $14.9 million, excluding corporate acquisitions was spent in capital expenditures. Of the capital expenditures, $14.0 million were directed to drilling, optimization and facility upgrades at West Pico, Santa Fe Springs and Orcutt. The remaining $0.9 million was directed at optimization projects at smaller fields and office equipment. For 2005, with the acquisition of the Wyoming properties, Provident is revising its annual capital expenditure program for USOGP from $41 million to $46 million. Canadian Oil and Gas Production (COGP COGP - Commission On Government Procurement COGP - Crude Oil Generating Plant) Provident's COGP business unit produces cash flow from the production and sale of natural gas, light/medium oil, NGLs, and heavy oil to energy marketers. Production assets are located in the central and southern regions of Alberta and Saskatchewan. In the first quarter of 2005, COGP generated $37.6 million of cash flow from operations compared to $26.4 million for the same period in 2004. First quarter 2005 production averaged 29,110 boed compared to 24,326 boed for the same period in 2004. The production increase reflects the acquisitions of Olympia and Viracocha in April 2004, as well as drilling and optimization activities offset by natural production declines. Production over the period is weighted 45 percent natural gas, 36 percent medium/light crude oil and natural gas liquids and 19 percent heavy oil. First quarter exit production was 28,233 boed as a result of natural declines and unanticipated downtime. Operating costs were $9.77/boe during the first quarter compared to $8.36/boe during the first quarter 2004 and $9.02/boe in the fourth quarter of 2004. The increase in operating expenses is due to the higher commodity price environment and the increased costs of well servicing, maintenance and fluid hauling. For 2005, given the aforementioned reasons, Provident is expecting operating costs around $9.50 to $9.90 per boe, assuming WTI prices of US$50 to US$55 per bbl. During the first quarter, Provident invested $14.1 million in development capital including $0.9 million spent in Lloydminster and $5.6 million in West Central and Southern Alberta on recompletion and drilling activities. Approximately $6.8 million was spent on acquiring mineral rights for future development, drilling for shallow gas and recompletions in Southeast and Southwest Saskatchewan with significant shallow gas drilling opportunity. For 2005, due to timing delays in executing capital projects in fourth quarter 2004, Provident is increasing its annual capital expenditure program for COGP from $69 million to $79 million to include these projects initiated in 2004. Provident Energy Trust is a Calgary-based, open-ended energy income trust that owns and manages an oil and gas production business 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.
Consolidated financial highlights
(000s except per unit amounts)
Consolidated
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Three months ended March 31,
($000s except per unit data) 2005 2004 (2) % Change
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Revenue (net of royalties and
financial derivative instruments)$ 322,023 $ 234,432 37
Cash flow from COGP operations 37,569 26,386 42
Cash flow from USOGP operations (1) 11,368 - -
Cash flow from midstream services
and marketing 15,200 9,883 54
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Total cash flow from operations $ 64,137 $ 36,269 77
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Per weighted average
unit - basic (3) 0.43 0.41 5
Per weighted average
unit - diluted (3) 0.43 0.41 5
Declared distributions
to unitholders 51,734 31,036 67
Per unit (4) 0.36 0.36 -
Percent of cash flow from
operations paid out as
declared distributions 81% 86% (6)
Net loss (2,839) (6,144) 54
Per weighted average
unit - basic (3) (0.02) (0.07) 71
Per weighted average
unit - diluted (3) (0.02) (0.07) 71
Capital expenditures 29,096 11,519 153
Nautilus acquisition 91,420 - -
Property acquisitions 90 4,718 (98)
Property dispositions 100 6,409 (98)
Weighted average trust units
and exchangeable
shares outstanding 149,206 88,041 69
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Consolidated
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As at As at
March 31, December 31,
($000s except per unit data) 2005 2004 (2) % Change
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Long-term debt $ 430,655 $ 432,206 -
Unitholders' equity $ 1,114,172 $ 1,044,969 7
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(1) No Q1 2004 comparitives as USOGP operations commenced
June 15, 2004.
(2) Restated for the impact of the retroactive implementation of the
change in accounting policies for convertible debentures - see
note 2
(3) Includes exchangeable shares
(4) Excludes exchangeable shares
Operational highlights
(000s except per unit amounts)
Consolidated
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Three months ended March 31, 2005 2004 % Change
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Oil and Gas Production
Daily production
Light/medium crude oil (bpd) 14,388 5,965 141
Heavy oil (bpd) 5,547 6,588 (16)
Natural gas liquids (bpd) 1,756 1,130 55
Natural gas (mcfpd) 80,466 63,859 26
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Oil equivalent (boed)(1) 35,102 24,326 44
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Average selling price (before hedges)
Light/medium crude oil ($/bbl) $ 49.32 $ 39.00 26
Heavy oil ($/bbl) $ 25.85 $ 26.84 (4)
Corporate oil blend ($/bbl) $ 42.63 $ 32.62 31
Natural gas liquids ($/bbl) $ 45.30 $ 37.03 22
Natural gas ($/mcf) $ 6.76 $ 6.40 6
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Oil equivalent ($/boe)( 1 ) $ 42.07 $ 35.34 19
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Field netback (before hedges) ($/boe) $ 24.22 $ 20.10 20
Field netback (including hedges)
($/boe) $ 20.78 $ 15.62 33
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Midstream services and marketing
Redwater throughput (bpd) 58,504 58,640 -
EBITDA (000s)(2) $16,380 $12,197 34
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(1) Provident reports oil equivalent production converting natural
gas to oil on a 6:1 basis.
(2) EBITDA is earnings before interest , taxes, depletion,
depreciation, accretion and non-cash revenue.
Management's discussion and analysis The following analysis provides a detailed explanation of Provident's operating results for the quarter ended March 31, 2005 compared to the quarter ended March 31, 2004 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. These include the impact of general economic conditions in Canada and the United States; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; increased competition; the lack of availability of qualified personnel or management; fluctuations in commodity prices; foreign exchange or interest rates; stock market volatility and obtaining required approvals of regulatory authorities. Provident's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking estimates and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking estimates will transpire, or if any of them do so, what benefits, including the amounts of proceeds, Provident will derive there from. All amounts are reported in Canadian dollars, unless otherwise stated. Provident Energy Trust has diversified investments in certain segments of the energy value chain. Provident currently operates in three key business segments: Canadian crude oil and natural gas production and exploitation ("COGP"), United States crude oil and natural gas production and exploitation, ("USOGP") and midstream services and marketing ("Midstream"). Provident's "COGP" business produces crude oil and natural gas from five core areas in the western Canadian sedimentary basin. USOGP produces crude oil and natural gas in Southern California and Wyoming, U.S.A. The Midstream business unit processes, markets, transports and offers storage of natural gas liquids at the Redwater facility and surrounding infrastructure located north of Edmonton, Alberta, 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. First quarter highlights The first quarter highlights section provides commentary on the first quarter 2005 results compared to the first quarter of 2004. Consolidated cash flow from operations and cash distributions Consolidated --------------------------------------------------------------------- Three months ended March 31, ($ 000s, except per unit data) 2005 2004 % Change --------------------------------------------------------------------- Revenue, Cash Flow and Distributions Revenue (net of royalties and financial derivative instruments - see note 7 of the financial statements) $ 322,023 $ 234,432 37 --------------------------------------------------------------------- Cash flow from operations before changes in working capital and site restoration expenditures $ 64,137 $ 36,269 77 Per weighted average unit - basic (1) $ 0.43 $ 0.41 5 Per weighted average unit - diluted (1) $ 0.43 $ 0.41 5 --------------------------------------------------------------------- Declared distributions $ 51,734 $ 31,036 67 Per Unit (2) 0.36 0.36 - Percent of cash flow distributed 81% 86% (6) --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Includes exchangeable shares (2) Excludes exchangeable shares First quarter 2005 cash flow was $64.1 million, 77 percent above the $36.3 million of cash flow recorded in the first quarter of 2004. COGP 2005 first quarter cash flow was $37.6 million a 42 percent improvement above the $26.4 million recorded in the comparable 2004 quarter. The main driver for this increase was the 20 percent increase in production volumes mainly attributed towards 2004 acquisitions, effective drilling programs, improved product pricing, product mix and netbacks. The Midstream business unit added $15.2 million to first quarter 2005 cash flow, 54 percent above the $9.9 million recorded in the comparable 2004 quarter. The Midstream cash flow benefited from efficient operations, marketing opportunities and increased revenues associated with storage and distribution services. Cash flow from operations also reflects $11.4 million of USOGP cash flow with no comparative for the like 2004 quarter. Declared distributions in the first quarter of 2005 totaled $51.7 million compared to $31.0 million of declared distributions in 2004. This represented 81 percent and 86 percent of cash flow from operations respectively.
Net loss
Consolidated
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Three months ended March 31,
($000s except per unit data) 2005 2004 (3) % Change
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Net loss $ (2,839) $ (6,144) 54
Per weighted average unit
- basic(1) $ (0.02) $ (0.07) 71
Per weighted average unit
- diluted(2) $ (0.02) $ (0.07) 71
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(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.
(3) Restated - note 2.
Net loss for the first quarter of 2005 improved 54 percent to $2.8 million compared to a $6.1 million net loss in the comparable 2004 quarter. Increased production from the second quarter 2004 acquisitions of Viracocha, Olympia and BreitBurn resulted in increased income. Included in the losses are pre-tax, unrealized losses, $23.8 million on hedges in the first quarter of 2005 and $22 million in the comparable first quarter of 2004. The COGP business segment's net loss is $9.8 million, comparable to a 2004 first quarter loss of $10.0 million. The Midstream unit contributed $12.5 million of net income in the first quarter of 2005 a 229 percent increase as compared to the $3.9 million of net income in the first quarter of 2004. In the first quarter of 2005, USOGP net losses were $5.6 million with no comparatives for the first quarter of 2004.
Taxes
Consolidated
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Three months ended March 31, ($ 000s) 2005 2004 % Change
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Capital taxes $ 1,377 $ 1,005 37
Current and withholding taxes 2,367 - -
Future income tax recovery (7,720) (14,549) (47)
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$ (3,976) $ (13,544) (71)
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Capital taxes in the first quarter totaled $1.4 million, an increase of 37 percent above the $1 million recorded in the first quarter of 2004. The increase reflects the growth in our Canadian asset base increasing 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 $2.4 million in the first quarter of 2005 with no comparative balance in the comparable 2004 quarter. These taxes arise from Provident's U.S based operations. This amount includes $0.9 million of estimated taxes accrued on 2004 operations. The reported taxes constitute 15.4 percent of first quarter USOGP EBITDA. Reported taxes for the year ended December 31, 2004 were 4.8 percent of USOGP EBITDA. Had the reported 2004 results included the $0.9 million of taxes on 2004 USOGP operations, the tax burden reported in the first quarter of 2005 would have been 9.5 percentof USOGP EBITDA and would have been 8.4 percent of USOGP EBITDA for the year ended December 31, 2004. The 2005 first quarter future tax recovery of $7.7 million on first quarter losses of $6.9 million exceeds the expected recovery of $2.6 million primarily as a result of interest and royalty charged by the Trust to its incorporated subsidiary, Provident Energy Ltd. These amounts are deductible in computing the income of the subsidiary. The Trust is a taxable entity under Canadian income tax law and is taxable only on income that is not distributed or distributable to the unit holders. If the Trust distributes all of its taxable income to the unitholders, no provision for taxes is required by the Trust. Recoveries of $14.5 million of future taxes in the first quarter of 2004 on losses before tax of $19.7 million exceeds the expected recovery of $7.5 million primarily for the same reasons. Reconciliation of GAAP The Trust calculates earnings before interest, taxes, depletion and accretion and non-cash revenue (EBITDA) within its segment disclosure. EBITDA is a non-GAAP measure. A reconciliation between EBITDA and loss before taxes follows:
EBITDA Reconciliation
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For the period ending March 31,
(000s, except per unit data) 2005 2004
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EBITDA $ 75,642 $ 42,938
Less:
Non-cash expenses excluding unrealized
loss on financial instruments 58,800 40,582
Unrealized loss on financial instruments 23,762 22,044
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Loss before taxes $ (6,920) $(19,688)
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Interest expense
Consolidated
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Three months ended March 31,
($000s except per unit data) 2005 2004 (1) % Change
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Interest on bank debt $ 3,326 $ 2,144 55
Weighted-average interest rate
on bank debt 4.1% 4.0% 3
Interest on 10.5% convertible
debentures 1,182 1,307 (10)
Interest on 8.75% convertible
debentures 1,599 1,636 (2)
Interest on 8.0% convertible
debentures (2) 1,029 - -
Interest on 6.5% convertible
debentures (3) 552 - -
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Total cash interest $ 7,688 5,087 51
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Weighted average interest rate
on all long-term debt 7.1% 5.4% -
Non -cash accretion expense
- convertible debentures 1,250 1,106 13
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Total interest including
accretion on convertible
debentures $ 8,938 $ 6,193 44
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(1) Restated - note 2.
(2) On July 6, 2004 the Trust issued $50.0 million of unsecured
subordinated convertible debentures with an 8 percent coupon rate
maturing July 31, 2009.
(3) On March 1, 2005 the Trust issued $100.0 million of unsecured
subordinated convertible debentures with a 6.5 percent coupon
rate maturing August 31, 2012.
Cash interest expense increased for the quarter as compared to the same quarter in 2004 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 adopting the revised CICA Handbook section 3860 and reclassifying the bulk of its subordinated convertible debentures to long-term debt and an additional portion to equity. Commodity Price Risk Management Program 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 March 31, 2005 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. During the first quarter of 2005, Provident entered into crude oil participating swaps for the period March 2005 to December 2005 and calendar 2006 at floor levels of US$45.00 per bbl and US$46.00 per bbl respectively, with participation percentages of 72 percent (2005) and 67 percent (2006) above the floor price. In the first quarter of 2005, Provident entered into April 2005 - December 2005 natural gas participating swaps, receiving an average floor price of $5.90 per gigajoule ("gj") and an average participation percentage of 61 percent. During the same period, Provident pre-sold a total of US $32.5 million at an average rate of $1.2342 to finance the acquisition of Nautilus. a) Crude oil For 2005, Provident paid out $10.6 million to settle various oil market based contracts on an aggregate volume of 1.3 million barrels. For the period ending March 31, 2004, Provident paid out $9.4 million to settle various oil market based contracts on an aggregate volume of 1.1 million barrels. The estimated value of contracts in place if settled at market prices at March 31, 2005 would have resulted in an opportunity cost of $46.0 million (March 31, 2004 -$28.9 million). The contracts in place at March 31, 2005 are summarized in the following table:
COGP
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2005
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Volume Remaining
Product (Bpd) Terms Effective Period
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Light Oil 2,750 WTI US $26.07 per bbl (1) April 1 - December 31
500 Costless collar
US $26.00 - $30.10 per bbl April 1 - December 31
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USOGP
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2005
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Volume Remaining
Product (Bpd) Terms Effective Period
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Light Oil 600 Puts US $35.00 per bbl April 1 -
June 30, 2005
500 Costless collar April 1 -
US$30.00 - $39.80 per bbl December 31, 2005
500 Costless collar April 1 -
US$30.00 - $39.50 per bbl December 31, 2005
500 Costless collar April 1 -
US$30.00-$39.37 per bbl December 31, 2005
500 Costless collar April 1 -
US$30.00 - $40.00 per bbl December 31, 2005
1,000 Participating Swaps April 1 -
US $45.50 per bbl December 31, 2005
(70% above floor price) (1) (2)
750 Puts US $40.00 per bbl April 1 -
December 31, 2005
500 Participating Swap
US $40.00 per bbl January 1 -
(66% above floor price) (2) December 31, 2006
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(1) Represents a number of transactions entered into over an extended
period of time.
(2) Provides a floor price while allowing percentage participation
above strike price.
b) Natural Gas For the period ending March 31, 2005, Provident paid $0.2 million to settle various natural gas market based contracts on an aggregate of 6.8 million gj's. For the period ending March 31 2004, Provident paid $0.5 million to settle various natural gas market based contracts on an aggregate of 5.5 million gj's. As at March 31, 2005 the estimated value of contracts in place settled at market prices at March 31 would have resulted in an opportunity loss of $2.6 million (March 31, 2004 - an opportunity cost of $11.1 million). The contracts in place at March 31, 2005 are summarized in the following table:
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2005
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Volume Remaining
Product (Gjpd) Terms Effective Period
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Natural 10,000 Participating Swaps April 1 - October 31
Gas (2) Cdn $6.00 per gj
(max to 73% above
floor price) (1) (3)
2,500 Puts Cdn $6.50 per gj April 1 - October 31
4,000 Participating Swaps June 1 - June 30
Cdn $5.93 per gj
(58% above floor price)(1)(3)
5,000 Participating Swap June 1 - October 31
Cdn $5.60 per gj
(55% above floor price) (3)
2,000 Participating Swap October 1 -
Cdn $5.75 per gj October 31
(60% above floor price) (3)
5,000 Participating Swap November 1 -
Cdn $6.80 per gj November 30
(64% above floor price) (3)
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(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.
c) Other Provident received $0.4 million on various midstream and marketing contracts which were entered into to fix prices on product sales ($0.2 million received March 31, 2004). There were no contracts on various midstream and marketing contracts outstanding as at March 31, 2005 ($0.6 million loss as at March 31, 2004). d) Foreign exchange contracts Provident had foreign exchange sell contracts in place for the period ending March 31, 2005 for a total gain of $0.1 million. As at March 31, 2005 the estimated value of contracts in place settles at foreign exchange rates would have resulted in an opportunity gain of $0.7 million. The foreign exchange gains have been included in note 7, as a component of realized loss on financial derivative instruments and allocated to their respective business segments. Goodwill Goodwill represents the excess of the cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed. Goodwill arose from the acquisitions of Richland Petroleum Corporation, $13.3 million, and Meota Resources Corp., $89.1 million in 2002 and from Olympia Energy Inc., $106.5 million, and Viracocha Energy Inc., $122.0 million in 2004. Goodwill is assessed for impairment at least annually. If impairment exists, it would be charged to income in the period in which the impairment occurs. Provident engaged an independent accounting firm to assist in performing an impairment test at the year-ending 2004. The impairment test included, among other variables, a comparison of the net book value of the Trust's assets to the market value of the Trust's equity. Goodwill is not amortized. Liquidity and capital resources Consolidated --------------------------------------------------------------------- As at, ($ 000s) 31-Mar-05 31-Dec-04 % Change --------------------------------------------------------------------- Long-term debt $ 430,655 $ 432,206 - Working capital deficit 61,635 38,677 59 --------------------------------------------------------------------- Net debt 492,290 470,883 5 --------------------------------------------------------------------- --------------------------------------------------------------------- Equity (at book value) 1,114,172 1,044,969 7 --------------------------------------------------------------------- Total capitalization at book value $ 1,606,462 $ 1,515,852 6 --------------------------------------------------------------------- --------------------------------------------------------------------- Net debt as a percentage of total book value capitalization 31% 31% - --------------------------------------------------------------------- --------------------------------------------------------------------- Provident operates three business units with similar but not identical monthly cash settlement cycles. Provident's working capital position is affected by seasonal fluctuations that reflect commodity price changes, drilling cycles in its oil and gas operations and inventory balances in its midstream business unit. Provident relies on cash flow from operations, external lines of credit and access to equity markets to fund capital programs and acquisitions. Long-term debt and working capital As at March 31, 2005 Provident had drawn $173.3 million or 42 percent of its term credit facility of $410.0 million as compared to $262.8 million or 64 percent drawn on its $410.0 million term credit facility as at December 31, 2004. The decrease in the level of bank debt was due primarily to the increase in convertible debentures. On March 1, 2005 the Trust issued $100.0 million ($95.8 million net of issue costs) of seven and half year unsecured subordinated convertible debentures with a 6.5 percent coupon rate maturing August 31, 2012. Convertible debentures are classified as long-term debt, excluding a minor equity component. At March 31, 2005 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 50 percent. The guarantees totaled $31.0 million at December 31, 2004. Provident's working capital decreased by $23.0 million as at March 31, 2005. Of this amount $23.3 million was due to unrealized hedging losses and a $1.9 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 partially offset by a $2.4 million decrease in petroleum product inventory. First quarter cash flow in 2005 was $64.1 million. The ratio of debt to annualized first quarter cash flow improved to 1.7 to one, as compared to fourth quarter annualized debt to cash flow in 2004 of 1.85 to one. Trust units and exchangeable shares On March 1, 2005 the Trust issued 8.4 million units at a price of $12.00 per unit for proceeds after underwriting fees of $95.6 million, concurrent with the issue of convertible debentures noted above. Proceeds from the issue were used to pay down Provident's bank debt and to finance the Nautilus Resources, LLC acquisition and throughout 2005 will be used to finance the company's 2005 capital budget and if required, be available to redeem the 10.5 percent convertible debentures. In the first quarter of 2005, the Trust also issued 1.3 million units (conversion amount $12.8 million) on conversion of exchangeable shares to units. The bulk of the publicly held exchangeable shares which were converted in the first quarter of 2005 were due to expire during the quarter. The Trust also issued 0.5 million units on conversion of convertible debentures and 1.1 million units pursuant to the stock option plan (2004 - nil and 0.1 million units respectively). Details of these issues are outlined in the notes to the financial statements. Under Provident's Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit Purchase Plan program 0.4 million units were issued or are to be issued representing proceeds of $4.4 million (2004 - 0.4 million units for proceeds of $4.6 million). On February 4, 2004 the Trust issued 4.5 million units at $11.20 per unit for proceeds of $50.4 million ($47.9 million net of issue costs) pursuant to a January 22, 2004 public offering. Proceeds from the issue were initially used to pay down Provident's bank debt and throughout 2004 were used to finance the company's 2004 capital budget. At March 31, 2005 management and directors held approximately 1.6 percent of the outstanding units and exchangeable shares. Non-controlling interest Non-controlling interest arose from Provident's June 15, 2004 acquisition of 92 percent of BreitBurn Energy of Los Angeles, California. The founders of BreitBurn Energy beneficially own the non-controlling interest, which share in earnings or losses of BreitBurn. The non-controlling interest is reduced by distributions. Consolidated --------------------------------------------------------------------- --------------------------------------------------------------------- ($ 000s) --------------------------------------------------------------------- Non-controlling interest, at December 31, 2004 $ 13,649 Non-controlling interest loss, period ending March 31, 2005 (105) Distributions to non-controlling interest holders, period ending March 31, 2005 (189) --------------------------------------------------------------------- --------------------------------------------------------------------- Non-controlling interest, as at March 31, 2005 $ 13,355 --------------------------------------------------------------------- --------------------------------------------------------------------- Additional investments by Provident in BreitBurn Energy LP have reduced the non-controlling interest percentage at March 31, 2005 to approximately 4.4 percent. Capital expenditures and funding Consolidated --------------------------------------------------------------------- Three months ended March 31, ($ 000s) 2005 2004 % Change --------------------------------------------------------------------- Capital Expenditures Capital expenditures and reclamation fund contributions $ 29,882 $ 12,071 148 Property acquisitions 90 4,718 (98) Corporate acquisitions 91,420 - - Property dispositions (100) (6,409) (98) --------------------------------------------------------------------- Net capital expenditures $ 121,292 $ 10,380 - --------------------------------------------------------------------- Funded By Cash flow net of declared distributions to unitholders and non-controlling interest $ 12,214 $ 5,233 133 Issue of convertible debentures, net of cost 95,759 - - Issue of trust units, net of cost; excluding DRIP 107,118 48,631 120 DRIP proceeds 4,429 4,604 (4) Change in working capital, including cash, and payment of financial derivative instruments (8,728) 9,612 (191) Decrease in bank debt (89,500) (57,700) 55 --------------------------------------------------------------------- Net capital expenditure funding $ 121,292 $ 10,380 - --------------------------------------------------------------------- --------------------------------------------------------------------- For the comparable quarters Provident has funded its net capital expenditures with cash flow, debt, working capital and equity issued from treasury through public offerings and the Premium DRIP program. Acquisition On March 2, 2005 the Trust, through its U.S. subsidiary, acquired Nautilus Resources, LLC for $90.2 million. At that time $8.1 million was paid to fully satisfy outstanding financial derivative instruments acquired through the Nautilus acquisition. This acquisition was financed through cash mainly raised through a trust unit issue of $95.6 million net of issue costs. Asset retirement obligation Consolidated --------------------------------------------------------------------- Three months ended March 31, ($ 000s) 2005 2004 % Change --------------------------------------------------------------------- Carrying amount, beginning of period $ 40,506 $ 33,182 22 Oil and gas corporate acquisitions 1,557 - - Increase in liabilities incurred during the period 121 329 (63) Settlement of liabilities during the period (629) (1,068) 41 Accretion of liability 795 580 37 --------------------------------------------------------------------- Carrying amount, end of period $ 42,350 $ 33,023 28 --------------------------------------------------------------------- --------------------------------------------------------------------- The asset retirement obligation (ARO) of $42.4 million increased 28 percent during the first quarter of 2005 mainly due to the Nautilus acquisition and accretion on historical balance partially offset by continuing settlement of abandonment and reclamation expenditures. 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 $140.7 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 $0.3 million for the quarter ended March 31, 2005 (2004 - recovery of $0.4 million). Subsequent Event On April 26, 2005 Provident announced its intention to redeem the aggregate amount of all outstanding 10.50 percent convertible unsecured subordinated debentures as of May 31, 2005 at an amount of $1,050 plus all accrued and unpaid interest hereon to May 30, 2005 per each $1,000 principal amount of debentures. At the option of the holder, each debenture is convertible into fully paid and non-assessable trust units at a price of $10.70 per trust unit, upon presentation and surrender of the debentures to the corporate office of Computershare Trust Company of Canada, located at Suite 710, 530 - 8 Avenue S.W. Calgary, Alberta, T2P 3S8, at anytime prior to 4:30pm (MDT) on May 30, 2005. The conversion rate is 93.4579 trust units per $1,000 principal amount of debentures. The debentures were originally issued to fund an acquisition of petroleum and natural gas assets and for general corporate purposes and were issued with a term that would have them mature on June 15, 2007. COGP segment review Crude oil and liquids price The following prices are net of transportation expense. COGP --------------------------------------------------------------------- Three months ended March 31, ($ per bbl) 2005 2004 % Change --------------------------------------------------------------------- Oil per barrel WTI (US$) $ 49.84 $ 35.16 42 Exchange rate (from US$ to Cdn$) 1.23 1.32 (7) WTI expressed in Cdn$ $ 61.30 $ 46.41 32 --------------------------------------------------------------------- --------------------------------------------------------------------- COGP --------------------------------------------------------------------- Three months ended March 31, ($ per boe) 2005 2004 % Change --------------------------------------------------------------------- Realized pricing before hedging Light/medium oil $ 45.96 $ 39.00 18 Heavy oil $ 25.85 $ 26.84 (4) Natural gas liquids $ 45.32 $ 37.03 22 --------------------------------------------------------------------- Crude oil and natural gas liquids $ 38.94 $ 32.98 18 --------------------------------------------------------------------- --------------------------------------------------------------------- Provident's realized oil and natural gas liquids price, prior to the impact of hedging, increased by 18 percent to $38.94 per barrel in the first quarter of 2005 compared to $32.98 per bbl in the first quarter of 2004. The 2005 increase related to a higher US$ WTI crude oil price partially offset by a stronger Canadian dollar and wider differentials on heavy oil pricing relative to WTI. Quarter over quarter ending March 31, 2005 and 2004 Provident reduced its volume of conventional heavy oil as a percentage of total mix from 27 percent in 2004 to 19 percent in 2005.
Natural gas price
The following prices are net of transportation expense.
COGP
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Three months ended March 31, ($ per mcf) 2005 2004 % Change
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AECO monthly index (Cdn$) per mcf $ 6.88 $ 6.60 4
Corporate natural gas price per mcf
before hedging (Cdn$) $ 6.75 $ 6.40 5
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---------------------------------------------------------------------
Provident's realized natural gas price, excluding hedges, increased
five percent in the first quarter of 2005 as compared to the first
quarter of 2004, slightly better than the increase in the benchmark
AECO index price increase of four percent.
Production
COGP
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Three months ended March 31, 2005 2004 % Change
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Daily production
Crude oil - Light/Medium (bpd) 8,763 5,965 47
- Heavy (bpd) 5,547 6,588 (16)
Natural gas liquids (bpd) 1,738 1,130 54
Natural gas (mcfd) 78,370 63,859 23
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Oil equivalent (boed) (1) 29,110 24,326 20
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(1) Provident reports equivalent production converting natural gas
to oil on a 6:1 basis.
Production increased 20 percent to 29,110 bpd during the first quarter of 2005 as compared to 24,326 bpd in 2004. The increase reflects the acquisition of Olympia and Viracocha to the COGP production base as well as drilling and optimization activities partially offset by natural production declines. Production over the quarter ended March 31, 2005 was weighted 45 percent natural gas, 19 percent heavy oil and 36 percent medium/light crude oil and natural gas liquids. Provident does not have any single property providing greater than 10 percent of daily production.
Provident's COGP production broken down by core areas is as follows:
COGP
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Three
months
ended West
March 31, Central Southern Southern
2005 Lloydminister Alberta Alberta Saskatchewan Other Total
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Daily
production
Crude oil
- Light/
Medium (bpd) 1,617 1,466 2,854 2,803 23 8,763
- Heavy (bpd) 5,547 - - - - 5,547
Natural gas
liquids (bpd) 15 1,589 132 1 1 1,738
Natural gas
(mcfd) 2,154 42,964 28,517 4,704 31 78,370
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Oil equivalent
(boed) (1) 7,538 10,216 7,739 3,588 29 29,110
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COGP
---------------------------------------------------------------------
Three
months
ended West
March 31, Central Southern Southern
2004 Lloydminister Alberta Alberta Saskatchewan Other Total
---------------------------------------------------------------------
Daily
production
Crude oil
- Light/
Medium (bpd) - 1,333 1,825 2,805 2 5,965
- Heavy (bpd) 6,588 - - - - 6,588
Natural gas
liquids (bpd) - 1,029 99 - 2 1,130
Natural gas
(mcfd) 1,684 41,249 18,314 2,558 54 63,859
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Oil equivalent
(boed) (1) 6,869 9,237 4,976 3,231 13 24,326
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(1) Provident reports equivalent production converting natural gas to
oil on a 6:1 basis.
Internal development activities included 11 net drills and during the quarter Provident added 500 BOEPD at initial productions rates through drilling, completion, workover and facility activity. Provident's most active area, southern Saskatchewan realized 6.7 net drills however, poor weather conditions have delayed tie-in operations. These wells will be tied-in during the second quarter of 2005. Provident expects COGP production for the full year to average between 27,400 boed and 28,000 boed. Revenue and royalties Revenue figures are presented net of transportation expense. COGP --------------------------------------------------------------------- Three months ended March 31, ($ 000s except per boe data) 2005 2004 % Change --------------------------------------------------------------------- Oil Revenue $ 49,153 $ 37,772 30 Realized loss on non-hedging derivative instruments (8,276) (9,397) (12) Royalties (net of ARTC) (8,923) (7,272) 23 --------------------------------------------------------------------- Net revenue $ 31,954 $ 21,103 51 --------------------------------------------------------------------- --------------------------------------------------------------------- Net revenue (per barrel) $ 24.81 $ 18.47 34 Royalties as a percentage of revenue 18.2% 19.3% --------------------------------------------------------------------- Natural gas Revenue $ 47,630 $ 37,138 28 Realized loss on non-hedging derivative instruments (183) (445) (59) Royalties (net of ARTC) (10,238) (6,971) 47 --------------------------------------------------------------------- Net revenue $ 37,209 $ 29,722 25 --------------------------------------------------------------------- --------------------------------------------------------------------- Net revenue (per mcf) $ 5.28 $ 5.11 3 Royalties as a percentage of revenue 21.5% 18.8% --------------------------------------------------------------------- Natural gas liquids Revenue $ 7,088 $ 3,808 86 Royalties (1,508) (1,002) 51 --------------------------------------------------------------------- Net revenue $ 5,580 $ 2,806 99 --------------------------------------------------------------------- --------------------------------------------------------------------- Net revenue (per barrel) $ 35.67 $ 27.29 31 Royalties as a percentage of revenue 21.3% 26.3% --------------------------------------------------------------------- Total Revenue $103,871 $ 78,718 32 Realized loss on non-hedging derivative instruments (8,459) (9,842) (14) Royalties (net of ARTC) (20,669) (15,245) 36 --------------------------------------------------------------------- Net revenue $ 74,743 $ 53,631 39 --------------------------------------------------------------------- --------------------------------------------------------------------- Net revenue per boe $ 28.53 $ 24.23 18 Royalties as a percentage of revenue 19.9% 19.4% --------------------------------------------------------------------- --------------------------------------------------------------------- Note: the above figures are presented net of transportation expenses. Quarter over quarter, 2005 COGP production revenue was $103.9 million, an increase of 32 percent from the $78.7 million in 2004. The increase in revenue incorporates a 20 percent increase in production volumes and an 18 percent increase in Provident' realized crude oil and natural gas liquids price. Royalties, which are price sensitive, increased as a percentage of revenue to 19.9 percent in the first quarter of 2005 from 19.4 percent for the comparable quarter in 2004. The preceding factors account for net revenue of $74.7 million in the first quarter of 2005, 39 percent above the $53.6 million recorded in the first quarter of 2004. Production expenses COGP --------------------------------------------------------------------- Three months ended March 31, (000s, except per boe data) 2005 2004 % Change --------------------------------------------------------------------- Production expenses $ 25,620 $ 18,504 38 Production expenses (per boe) $ 9.77 $ 8.36 17 --------------------------------------------------------------------- --------------------------------------------------------------------- First quarter 2005 production expenses increased 38 percent to $25.6 million from $18.5 million in the comparable 2004 quarter. The increase coincides with the equivalent increase in production volumes as a result of the Olympia and Viracocha acquisitions. However, on a boe basis quarter-over-quarter production expenses have risen to $9.77 per boe, which is a 17 percent increase when compared to $8.36 per boe in the like 2004 quarter. Operating expenses increased in a number of categories including well servicing, maintenance, power and fuel, chemicals and fluid hauling. This is a result of poor weather conditions experienced during the first quarter, and, in addition, commodity prices have risen sharply in 2005 causing increases in services costs throughout all of Provident's Canadian oil and gas operations. Based on the current high commodity price environment and increased levels of activity, Provident expects its operating costs to average $9.50 per boe to $9.90 per boe for 2005. Commodity prices affect the price of services. If commodity prices increase, Provident expects the price of services to increase. Operating netback COGP operating netbacks have transportation expense netted against gross production revenue. COGP --------------------------------------------------------------------- Three months ended March 31, ($ per boe) 2005 2004 % Change --------------------------------------------------------------------- COGP oil equivalent netback per boe Gross production revenue $ 39.65 $ 35.56 12 Royalties (net of ARTC) (7.89) (6.89) 15 Operating costs (9.77) (8.36) 17 --------------------------------------------------------------------- Field operating netback $ 21.99 $ 20.31 8 --------------------------------------------------------------------- --------------------------------------------------------------------- Realized loss on cash hedging (3.23) (4.45) (27) --------------------------------------------------------------------- Operating netback after hedging $ 18.76 $ 15.86 18 --------------------------------------------------------------------- --------------------------------------------------------------------- First quarter 2005 field operating netback of $21.99 per boe was eight percent above the $20.31 per boe in the same quarter in 2004. The increasing field operating netback in the first quarter of 2005 reflects a higher WTI crude oil benchmark and a significant shift in Provident's production mix to include a greater weighting towards natural gas and lighter grades of crude oil partially offset by wider differentials and increases in royalties and operating costs. Operating netbacks after hedging increased by 18 percent to $18.76 from $15.86 reflecting the first quarter opportunity cost due to hedging of $3.23 per boe compared to $4.45 in the comparable quarter in 2004. Netbacks by product for crude oil and NGL's and natural gas are as follows: COGP --------------------------------------------------------------------- Three months ended March 31, ($ per bbl) 2005 2004 % Change --------------------------------------------------------------------- COGP crude oil and NGL's netback per bbl Gross production revenue $ 38.94 $ 32.98 18 Royalties (net of ARTC) (7.22) (6.64) 9 Operating costs (9.13) (6.76) 35 --------------------------------------------------------------------- Field operating netback 22.59 19.58 15 --------------------------------------------------------------------- --------------------------------------------------------------------- Realized loss on cash hedging (5.73) (7.55) (24) --------------------------------------------------------------------- Operating netback after hedging $ 16.86 $ 12.03 40 --------------------------------------------------------------------- --------------------------------------------------------------------- COGP --------------------------------------------------------------------- Three months ended March 31, ($ per mcf) 2005 2004 % Change --------------------------------------------------------------------- COGP natural gas netback per mcf Gross production revenue $ 6.75 $ 6.40 5 Royalties (net of ARTC) (1.45) (1.20) 21 Operating costs (1.77) (1.73) 2 --------------------------------------------------------------------- Field operating netback 3.53 3.47 2 --------------------------------------------------------------------- --------------------------------------------------------------------- Realized loss on cash hedging (0.03) (0.08) (63) --------------------------------------------------------------------- Operating netback after hedging $ 3.50 $ 3.39 3 --------------------------------------------------------------------- --------------------------------------------------------------------- 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. First quarter non-cash general and administrative expenses for COGP totaled $0.3 million. COGP --------------------------------------------------------------------- Three months ended March 31, ($ 000s, except per boe data) 2005 2004 % Change --------------------------------------------------------------------- Cash general and administrative $4,483 $4,386 2 Cash general and administrative per boe $ 1.71 $ 1.98 (14) --------------------------------------------------------------------- --------------------------------------------------------------------- Cash general and administrative expenses for COGP in the first quarter increased two percent to $4.5 million from $4.4 million recorded in the 2004 comparable quarter. On a boe basis the cash general and administrative expenses recorded in the first quarter 2005 decreased 14 percent to $1.71 from $1.98 in the first quarter of 2004. 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. Capital expenditures COGP --------------------------------------------------------------------- --------------------------------------------------------------------- Three months ended March 31, ($000s) 2005 2004 --------------------------------------------------------------------- Capital expenditures Lloydminster $ 942 $ 500 West central and southern Alberta 5,640 2,190 Southeast and southwest Saskatchewan 6,757 7,750 Office and other 720 540 --------------------------------------------------------------------- Total additions $ 14,059 $ 10,980 --------------------------------------------------------------------- --------------------------------------------------------------------- Property acquisitions 90 4,718 Property dispositions $ 100 $ 6,409 --------------------------------------------------------------------- --------------------------------------------------------------------- In the first quarter of 2005, Provident's COGP business unit spent $0.9 million in the Lloydminster core area on workovers and facility work. In the west central area $1.7 million was spent largely on non-operated capital and in the southern Alberta core area $3.9 million was spent on drilling activities, recompletions and facility upgrades. Provident spent $6.8 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 $0.7 million of capital. The first quarter capital program will realize approximately 500 boed at initial production rates through drilling, completion, workover and facility activity. In the first quarter of 2005 asset dispositions of non-core assets totaled $0.1 million compared to $6.4 million in the first quarter of 2004. Provident will seek to dispose of its non-core properties given the competitive property market. The 2005 COGP capital budget is $78.8 million. Depletion, depreciation and accretion (DD&A) COGP --------------------------------------------------------------------- Three months ended March 31, ($000s, except per boe data) 2005 2004 % Change --------------------------------------------------------------------- DD&A $ 41,552 $ 32,153 29 DD&A per boe $ 15.86 $ 14.53 9 --------------------------------------------------------------------- --------------------------------------------------------------------- The COGP DD&A of $15.86 per boe increased nine percent for the first quarter of 2005 compared to $14.53 per boe for the first quarter of 2004. The increase is mainly due to the cost of acquiring proved reserves in the second quarter of 2004 in western Canada in an environment where reserve costs escalated with higher commodity prices. The result was proved reserves in 2004 were acquired at a higher cost per boe than Provident's historical asset base. In the first quarter 2005 and of 2004 DD&A also includes accretion expense associated with asset retirement obligations of $0.6 million. 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 first quarter comparative figures for 2004. On March 2, 2005 Breitburn acquired Nautilus Resources, LLC, a U.S. private company with operations focused in the Big Horn and Wind River basins of Wyoming for cash consideration of $90.2 million. USOGP pricing The following prices are net of transportation expenses. USOGP --------------------------------------------------------------------- Three months ended March 31, 2005 --------------------------------------------------------------------- Realized pricing before hedging Light/medium oil and natural gas liquids (Cdn$ per bbl) $ 54.00 USOGP natural gas price per mcf before hedging (Cdn$ per mcf) $ 7.12 --------------------------------------------------------------------- Oil equivalent (Cdn$ per boe) $ 53.35 --------------------------------------------------------------------- --------------------------------------------------------------------- The majority of USOGP oil production is light, sweet crude that attracts smaller differentials to benchmark prices relative to heavier blends. However, the oil production from the recently acquired Nautilus properties is heavier and attracts slightly wider differentials. Production from the former Nautilus properties represents approximately 30 percent of quarter exit rates and is anticipated to have an impact on realized pricing as the effect of the wider differential Wyoming properties are included in a full quarter of results.
Production
USOGP
---------------------------------------------------------------------
For the three months ended March 31, 2005
---------------------------------------------------------------------
Daily production
Crude oil - Light/Medium (bpd) 5,625
Natural gas liquids (bpd) 18
Natural gas (mcfd) 2,096
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Oil equivalent (boed) (1) 5,992
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas
to oil on a 6:1 basis.
USOGP production increased 1,755 boed in the first quarter of 2005 when compared to production during the period June 15 to December 31, 2004. The increase is primarily attributable to the first full quarter of the October 4th acquired Orcutt properties that added 1,344 boed combined with one month of the Nautilus properties production that added 2,225 boed. The USOGP exit production rate for the first quarter of 2005 was approximately 7,400 boed. Provident expects USOGP production for the remainder of the year to average between 8,200 boed and 8,400 boed. Revenue and royalties The following table outlines USOGP revenue and royalties by product line. The table excludes revenues earned from operating certain properties ($0.3 million) on behalf of third parties. USOGP --------------------------------------------------------------------- Three months ended March 31, ($ 000s, except per boe amounts) 2005 --------------------------------------------------------------------- Oil Revenue $ 27,354 Realized loss on non-hedging derivative instrument (2,354) Royalties (2,477) --------------------------------------------------------------------- Net revenue $ 22,523 --------------------------------------------------------------------- --------------------------------------------------------------------- Net revenue (per bbl) $ 44.49 Royalties as a percentage of revenue 9.1% --------------------------------------------------------------------- Natural gas Revenue $ 1,343 Royalties (186) --------------------------------------------------------------------- Net revenue $ 1,157 --------------------------------------------------------------------- --------------------------------------------------------------------- Net revenue (per mcf) $ 6.13 Royalties as a percentage of revenue 13.8% --------------------------------------------------------------------- Natural gas liquids Revenue $ 71 Royalties (2) --------------------------------------------------------------------- Net revenue $ 69 --------------------------------------------------------------------- --------------------------------------------------------------------- Net revenue (per bbl) $ 42.60 Royalties as a percentage of revenue 2.8% --------------------------------------------------------------------- Total Revenue $ 28,768 Realized loss on non-hedging derivative instrument (2,354) Royalties (2,665) --------------------------------------------------------------------- Net revenue $ 23,749 --------------------------------------------------------------------- --------------------------------------------------------------------- Net revenue (per boe) $ 44.04 Royalties as a percentage of revenue 9.3% --------------------------------------------------------------------- --------------------------------------------------------------------- Royalty rates in the U.S. are significantly lower than in Canada Production expenses USOGP --------------------------------------------------------------------- Three months ended March 31, ($ 000s, except per boe amounts) 2005 --------------------------------------------------------------------- Production expenses $ 7,426 Production expenses (per boe) $ 13.77 --------------------------------------------------------------------- --------------------------------------------------------------------- Production expenses are $13.77 per boe. This is 12 percent lower than production expenses incurred during 2004. This is mainly due to the lower operating costs of the Wyoming properties amalgamated from the Nautilus acquisition. These newly acquired properties, on average, have lower operating costs than costs incurred in the Los Angeles basin or at Orcutt. The favorable production variance was partially offset by higher operating costs incurred on wells that were returned to production to take advantage of higher crude oil pricing. For the remainder of 2005 operating costs are expected to remain in the $13.00 to $13.50 per boe range (assuming an exchange rate of Cdn $1.25 per US $1.00). 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. A period to date non-cash expense for the unit appreciation rights plan of $0.4 million has been recognized in 2005. USOGP --------------------------------------------------------------------- Three months ended March 31, ($ 000s, except per boe amounts) 2005 --------------------------------------------------------------------- Cash general and administrative $ 1,771 Cash general and administrative per boe $ 3.28 --------------------------------------------------------------------- --------------------------------------------------------------------- Cash general and administrative expenses in the first quarter are $1.8 million or $3.28 per boe. General and administrative expenses during the first quarter are $1.57 lower then the fourth quarter of 2004, a 32 percent favorable variance. This is primarily due to the addition of Nautilus that was absorbed without a significant increase in general and administrative expenses. Operating netback USOGP --------------------------------------------------------------------- Three months ended March 31, ($ per boe) 2005 --------------------------------------------------------------------- USOGP oil equivalent netback per boe Gross production revenue $ 53.35 Royalties (4.94) Operating costs (13.77) --------------------------------------------------------------------- Field Operating Netback $ 34.64 --------------------------------------------------------------------- --------------------------------------------------------------------- Cash hedging (4.37) --------------------------------------------------------------------- Operating netback after hedging $ 30.27 --------------------------------------------------------------------- --------------------------------------------------------------------- USOGP natural gas netback per mcf Gross production revenue $ 7.12 Royalties (0.99) Operating costs (0.90) --------------------------------------------------------------------- Field Operating Netback $ 5.23 --------------------------------------------------------------------- --------------------------------------------------------------------- Cash hedging - --------------------------------------------------------------------- Operating netback after hedging $ 5.23 --------------------------------------------------------------------- --------------------------------------------------------------------- USOGP --------------------------------------------------------------------- Three months ended March 31, ($ per bbl) 2005 --------------------------------------------------------------------- USOGP crude oil and NGL's netback per bbl Gross production revenue $ 54.00 Royalties (4.88) Operating costs (14.29) --------------------------------------------------------------------- Field Operating Netback $ 34.83 --------------------------------------------------------------------- --------------------------------------------------------------------- Cash hedging (4.64) --------------------------------------------------------------------- Operating netback after hedging $ 30.19 --------------------------------------------------------------------- --------------------------------------------------------------------- Operating netbacks in the first quarter of 2005 remain strong driven by high commodity prices partially offset by increased operating cost and opportunity costs associated with hedge activities. Capital expenditures USOGP capital expenditures, excluding corporate acquisitions, for the period ended March 31, 2005 totaled $14.9 million. $14.0 million of the capital expenditures were directed at drilling, optimization and facility upgrades at West Pico, Santa Fe Springs and Orcutt. The remaining $0.9 million was directed at optimization projects at smaller fields and office equipment. A significant portion of optimization capital was directed at improvements to infrastructure aimed at reducing future operating expenses. In addition, optimization capital continues to incorporate returning previously uneconomic wells to production to take advantage of higher oil pricing. Corporate acquisitions for the first quarter added $99.9 million to property, plant and equipment. The capital budget for 2005 is $46.0 million. Depletion, depreciation and accretion (DD&A) USOGP --------------------------------------------------------------------- Three months ended March 31, ($ 000s, except per boe amounts) 2005 --------------------------------------------------------------------- DD&A $ 5,107 DD&A per boe $ 9.47 --------------------------------------------------------------------- --------------------------------------------------------------------- The USOGP's DD&A rate is low due to the long-lived nature of the assets. 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 barrel 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 over the year. Operations - throughput First quarter 2005 throughput at the Redwater fractionation facility averaged 58,504 bpd which was consistent with 58,640 in the first quarter of 2004, reflecting seasonal volumes. The midstream and marketing business unit managed an average of 61,590 bbld in the first quarter of 2005 as compared to 66,907 in the first quarter of 2004. This includes volumes fractionated at the Redwater plant and at third party facilities. Revenues 2005 first quarter product sales and services revenues of $244.9 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 $219.6 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 T&F and marketing contracts and a small percentage of volume delivered from the Younger facility on which Provident retains fractionation risk. The majority of the natural gas liquids are purchased pursuant to long-term contracts and annual evergreen purchase commitments. Other expenses The plant has modern technology and low cost operations. First quarter 2005 operating costs of $7.4 million (quarter ended 2004 - $9.0 million) represent normal operations. General and administrative expenses is $2.0 million for the first quarter 2005 (2004 - $0.9 million), interest is $1.4 million for 2005 (2004 - $2.4 million), and depreciation of $2.5 million for 2005 (2004 - $2.3 million). Earnings before interest, taxes, depletion, depreciation, accretion, and non-cash revenue ("EBITDA") and cash flow from operations The first quarter of 2005 results for the Midstream services and marketing business unit reflected in EBITDA, cash flow and net income benefited from continuing efficient operations, marketing opportunities and increased revenues associated with storage and distribution services. First quarter 2005 EBITDA of $16.4 million increased 34 percent from $12.2 million in the first quarter of 2004. Cash flow for the first quarter of 2005 was $15.2 million an increase of 54 percent above the $9.9 million for the first quarter 2004. First quarter net income at $12.5 million was 221 percent above the $ 3.9 million of net income recorded in the first quarter of 2004. Management's 2005 forecast for Midstream EBITDA is $42.0 - $46.0 million. Management uses EBITDA to analyze the operating performance of the midstream business unit. EBITDA as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. EBITDA as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to EBITDA throughout this report are based on Earnings before interest, taxes, depletion, depreciation, accretion, and non-cash revenue ("EBITDA").
Distributions
The following table summarizes distributions paid or declared by the
Trust since inception:
---------------------------------------------------------------------
Distribution Amount
Record Date Payment Date (Cdn$) (US$)(1)
---------------------------------------------------------------------
2005
January 20, 2005 February 15, 2005 $ 0.12 $ 0.10
February 18, 2005 March 15, 2005 0.12 0.10
March 21, 2005 April 15, 2005 0.12 0.10
---------------------------------------------------------------------
Q1 2005 Cash Distributions
paid as declared $ 0.36 $ 0.30
---------------------------------------------------------------------
---------------------------------------------------------------------
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 March 31, 2005
- Distributions paid as declared $ 8.43 $ 5.80
---------------------------------------------------------------------
---------------------------------------------------------------------
(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. Foreign ownership Since January 2002, Provident has seen increased trading volumes and levels of ownership by non-residents of Canada. Based on information received from the transfer agent and financial intermediaries in March 2005, an estimated 85 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 per cent Canadian ownership standard and that there would be withholding taxes on all distributions to non-residents of Canada. The specific legislation providing the details of the changes was tabled in mid-September. These changes would have required that Provident have 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 does not include restrictions upon foreign ownership of mutual fund trusts as was previously proposed in draft legislation on September 16, 2004. Under the terms of the Notice, non-resident taxable and 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. Business prospects Provident intends to execute a balanced portfolio strategy. In the COGP business internal development projects with a capital budget of $78.8 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 net capital expenditures of $20.9 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. 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. 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. 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. Changes in accounting policies No changes in accounting policy were adopted by Provident for the first quarter of 2005. Recent accounting pronouncements The following new accounting guidelines or standards have been reviewed by Provident but have been assessed as not having any impact on Provident's financial results for the period ending March 31, 2005. 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. This guideline does not have a material impact on the Trust. Exchangeable shares The CICA has issued an EIC, "Income trusts - exchangeable shares." This standard would have the effect of reclassifying exchangeable shares from equity to non-controlling interest on the consolidated financial statements, and to allocate a portion of net income or loss to this non-controlling interest. At March 31, 2005 there was $21.6 million of exchangeable shares which would have been reclassified from equity to non-controlling interest had the standard been adopted in the first quarter of 2005. This standard will be adopted in the second quarter of 2005 as required by the EIC. 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 three months ended March 31, 2005 on both the Toronto Stock Exchange and the American Stock Exchange:
---------------------------------------------------------------------
Three months ended March 31,
($ 000s, except per boe amounts) Q1
---------------------------------------------------------------------
TSE - PVE.UN (Cdn$)
High $ 12.60
Low $ 11.14
Close $ 11.98
Volume (000s) 26,122
---------------------------------------------------------------------
---------------------------------------------------------------------
AMEX - PVX (US$)
High $ 10.40
Low $ 9.15
Close $ 9.89
Volume (000s) 64,223
---------------------------------------------------------------------
---------------------------------------------------------------------
Segmented information by quarter
---------------------------------------------------------------------
($000s except for per unit amounts) 2005
---------------------------------------------------------------------
First
Quarter
------------
Financial - consolidated
Revenue $ 322,023
Cash flow $ 64,137
Net income (loss) $ (2,839)
Unitholder distributions $ 51,734
Distributions per unit $ 0.36
---------------------------------------------------------------------
Oil and gas production
Cash revenue $ 100,447
Earnings before interest, DD&A, taxes
and other non-cash items $ 59,262
Cash flow $ 48,937
Net income (loss) $ (15,350)
---------------------------------------------------------------------
Midstream services and marketing
Cash revenue $ 245,338
Earnings before interest, DD&A and
taxes $ 16,380
Cash flow $ 15,200
Net income $ 12,511
---------------------------------------------------------------------
Operating
Oil and gas production
Light/medium oil (bpd) 14,388
Heavy oil (bpd) 5,547
Natural gas liquids (bpd) 1,756
Natural gas (mcfd) 80,466
Oil equivalent (boed) 35,102
---------------------------------------------------------------------
(Cdn $)
Average
Light/medium oil per bbl $ 49.32
(before hedges)
Light/medium oil per bbl
(including hedges) $ 40.93
Heavy oil per bbl
(before hedges) $ 25.85
Heavy oil per bbl
(including hedges) $ 25.78
Natural gas liquids per barrel $ 45.30
Natural gas per mcf
(before hedges) $ 6.76
Natural gas per mcf
(including hedges) $ 6.74
---------------------------------------------------------------------
Midstream services and marketing
Redwater throughput (bpd) 58,504
---------------------------------------------------------------------
---------------------------------------------------------------------
Segmented information by quarter
---------------------------------------------------------------------
($000s except per unit amounts) 2004
---------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter YTD Total
(1) (1) (1)
--------- --------- --------- --------- -----------
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
(loss) $ (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 $ 91,569 $ 294,879
Earnings before
interest, DD&A,
taxes and other
non-cash items $ 30,741 $ 34,974 $ 51,767 $ 50,498 $ 167,980
Cash flow $ 26,386 $ 29,593 $ 44,825 $ 41,798 $ 142,602
Net income
(loss) $(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
---------------------------------------------------------------------
(Cdn $)
Average selling
price net of
transportation
expense
Light/medium
oil per bbl
(before
hedges) $ 39.00 $ 42.28 $ 48.59 $ 45.83 $ 45.01
Light/medium
oil per bbl
(including
hedges) $ 26.15 $ 29.97 $ 38.00 $ 33.88 $ 33.29
Heavy oil
per bbl
(before
hedges) $ 26.84 $ 28.26 $ 34.23 $ 25.33 $ 28.72
Heavy oil
per bbl
(including
hedges) $ 22.80 $ 23.26 $ 25.72 $ 22.17 $ 23.51
Natural gas
liquids per
barrel $ 37.03 $ 40.55 $ 40.88 $ 42.80 $ 40.68
Natural gas
per mcf
(before
hedges) $ 6.40 $ 7.01 $ 6.47 $ 6.56 $ 6.60
Natural gas
per mcf
(including
hedges) $ 6.31 $ 6.26 $ 6.05 $ 6.31 $ 6.23
---------------------------------------------------------------------
Midstream
services and
marketing
Redwater
throughput
(bpd) 58,640 48,452 55,759 56,599 55,120
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2.
Segmented information by quarter
---------------------------------------------------------------------
($000s except per unit amounts) 2003(1)
---------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter YTD 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
(loss) $(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 (loss) $(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
---------------------------------------------------------------------
(Cdn $ per boe)
Average selling
price net of
transportation
expense
Light/medium
oil per bbl
(before
hedges) $ 43.64 $ 33.57 $ 33.49 $ 32.79 $ 36.02
Light/medium
oil per bbl
(including
hedges) $ 32.04 $ 29.18 $ 28.24 $ 26.61 $ 29.09
Heavy oil
per bbl
(before
hedges) $ 31.63 $ 23.47 $ 24.17 $ 20.61 $ 24.74
Heavy oil
per bbl
(including
hedges) $ 24.63 $ 21.92 $ 22.16 $ 20.25 $ 22.09
Natural gas
liquids per
barrel $ 45.13 $ 37.16 $ 28.26 $ 34.48 $ 35.87
Natural gas
per mcf
(before
hedges) $ 7.94 $ 6.87 $ 5.88 $ 5.62 $ 6.63
Natural gas
per mcf
(including
hedges) $ 6.49 $ 5.64 $ 5.14 $ 5.48 $ 5.71
---------------------------------------------------------------------
Midstream
services and
marketing
Redwater
throughput
(bpd) - - - 63,616 N/A
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2.
PROVIDENT ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
Canadian Dollars (000s)
(unaudited)
As at As at
March 31, December 31,
2005 2004
-----------------------------
(restated
note 2)
Assets
Current assets
Cash $ 194 $ 244
Accounts receivable 171,611 143,142
Petroleum product inventory 14,717 17,151
Deferred derivative loss (note 10) 1,755 2,144
Prepaid expenses 8,829 10,265
---------------------------------------------------------------------
197,106 172,946
Cash reserve for future site reclamation 1,611 1,454
Investments 3,030 3,000
Deferred financing charges 9,736 5,584
Property, plant and equipment 1,379,755 1,299,654
Goodwill 330,944 330,944
---------------------------------------------------------------------
$ 1,922,182 $ 1,813,582
---------------------------------------------------------------------
---------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued
liabilities $ 193,352 $ 171,412
Cash distributions payable 17,303 15,416
Distribution payable to
non-controlling interest 189 271
Financial derivative instruments 47,897 24,524
---------------------------------------------------------------------
258,741 211,623
Long-term debt (note 4) 430,655 432,206
Asset retirement obligation (note 5) 42,350 40,506
Future income taxes 62,909 70,629
Non-controlling interest 13,355 13,649
Unitholders' Equity
Unitholders' contributions (note 6) 1,568,225 1,438,393
Exchangeable shares (note 6) 21,633 34,439
Convertible debentures equity
component (note 2) 17,606 9,785
Contributed surplus (note 8) 1,606 2,002
Cumulative translation adjustment
(note 2) (29,523) (28,848)
Accumulated income (loss) (995) 1,844
Accumulated cash distributions (note 9) (464,380) (412,646)
---------------------------------------------------------------------
1,114,172 1,044,969
---------------------------------------------------------------------
$ 1,922,182 $ 1,813,582
---------------------------------------------------------------------
---------------------------------------------------------------------
Subsequent event (note 11)
PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED INCOME (LOSS)
Canadian dollars (000s except per unit amounts)
(unaudited)
Quarter ended March 31,
-----------------------------
2005 2004
-----------------------------
(restated note 2)
Revenue (note 7)
Revenue $ 356,123 $ 266,132
Realized loss on financial
derivative instruments (10,338) (9,656)
Unrealized loss on financial
derivative instruments (23,762) (22,044)
---------------------------------------------------------------------
322,023 234,432
Expenses
Cost of goods sold 219,620 180,021
Production, operating and maintenance 40,421 27,548
Transportation 1,692 1,234
General and administrative 8,277 5,250
Non cash general and administrative 631 (419)
Interest on bank debt 3,326 2,144
Interest and accretion on convertible
debentures (notes 2 and 4) 5,612 4,049
Amortization of deferred financing
charges 90 359
Foreign exchange (gain) losses 113 (515)
Depletion, depreciation and accretion 49,161 34,449
---------------------------------------------------------------------
328,943 254,120
---------------------------------------------------------------------
Loss before taxes (6,920) (19,688)
---------------------------------------------------------------------
Capital taxes 1,377 1,005
Current and withholding taxes 2,367 -
Future income tax recovery (7,720) (14,549)
---------------------------------------------------------------------
(3,976) (13,544)
Net loss before non-controlling interest (2,944) (6,144)
---------------------------------------------------------------------
Non-controlling interest loss (105) -
---------------------------------------------------------------------
Net loss (2,839) (6,144)
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated income (loss),
beginning of period 1,844 (4,029)
Retroactive application of changes in
accounting policies - (15,809)
---------------------------------------------------------------------
Accumulated income (loss),
beginning of period, restated 1,844 (19,838)
---------------------------------------------------------------------
Accumulated loss, end of period $ (995) $ (25,982)
---------------------------------------------------------------------
Net loss per unit - basic $ (0.02) $ (0.07)
---------------------------------------------------------------------
---------------------------------------------------------------------
Net loss per unit - diluted $ (0.02) $ (0.07)
---------------------------------------------------------------------
---------------------------------------------------------------------
PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
Canadian Dollars (000s)
(unaudited)
Quarter ended March 31,
-----------------------------
2005 2004
-----------------------------
(restated note 2)
Cash provided by operating activities
Net loss for the period $ (2,839) $ (6,144)
Add non-cash items:
Depletion, depreciation and accretion 49,161 34,449
Debenture accretion and amortization of
deferred charges (note 2) 1,297 888
Non-cash general and administrative
(note 7) 631 (419)
Unrealized loss on non-hedging derivative
instruments (note 7) 23,762 22,044
Unrealized foreign exchange gain (20) -
Future income tax recovery (7,720) (14,549)
Equity in earnings of investee (30) -
Non-controlling interest loss (105) -
---------------------------------------------------------------------
Cash flow from operations before changes
in working capital and site restoration
expenditures 64,137 36,269
---------------------------------------------------------------------
Site restoration expenditures (629) (1,068)
Change in non-cash operating working
capital (4,801) 8,804
---------------------------------------------------------------------
58,707 44,005
---------------------------------------------------------------------
Cash used for financing activities
Repayments of long-term debt (89,500) (57,700)
Declared distributions to
unitholders (note 9) (51,734) (31,036)
Declared distributions to
non-controlling interest (189) -
Issue of trust units, net of issue costs 111,547 53,235
Issue of debenture, net of costs 95,759 -
Change in non-cash financing working
capital 4,760 780
---------------------------------------------------------------------
70,643 (34,721)
---------------------------------------------------------------------
Cash used for investing activities
Net capital expenditures (29,086) (9,828)
Acquisition of Nautilus (note 3) (91,420) -
Reclamation fund contributions (786) (552)
Reclamation fund withdrawals 629 1,068
Payment of non-hedging derivative
instruments (note 3) (8,137) -
Change in non-cash investing working
capital (600) 75
---------------------------------------------------------------------
(129,400) (9,237)
---------------------------------------------------------------------
Increase (decrease) in cash (50) 47
Cash beginning of year 244 45
---------------------------------------------------------------------
Cash end of year $ 194 $ 92
---------------------------------------------------------------------
---------------------------------------------------------------------
Supplemental disclosure of cash flow
information
Cash interest paid including debenture
interest $ 6,366 $ 2,467
---------------------------------------------------------------------
---------------------------------------------------------------------
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in Cdn$000's, except unit and per unit amounts)
(unaudited)
March 31, 2005
The Interim Consolidated Financial Statements of Provident Energy Trust ("the Trust") have been prepared by management in accordance with accounting principals generally accepted in Canada. Certain information and disclosures normally required in the notes to the annual financial statements have been condensed or omitted. The Interim Consolidated Financial Statements should be read in conjunction with the Trust's audited Financial Statements and notes for the year ended December 31, 2004, which are disclosed in the annual report filed by the Trust. 1. Significant accounting policies The interim Consolidated Financial Statements have been prepared based on the consistent application of the accounting policies and procedures as set out in the Financial Statements of the Trust for the year ended December 31, 2004 and are consistant with policies adopted in the first quarter of 2004 except as described in note 2. 2. Changes in accounting policies and practices (i) Convertible debentures Effective December 31, 2004, the Trust retroactively adopted the revised CICA Handbook Section 3860 ("HB 3860"), "Financial Instruments - Presentation and Disclosure" for financial instruments that may be settled at the issuer's option in cash or its own equity. The revised standard requires the Trust to classify proceeds from convertible debentures issued in 2002, 2003 and 2004 as either debt or equity based on fair value measurement and the substance of the contractual arrangement. The Trust previously presented the convertible debenture proceeds (net of financing costs) and related interest obligations as equity on the consolidated balance sheet on the basis that the Trust could settle its obligations in exchange for trust units. Issue costs on convertible debentures are recorded as deferred financing charges and are amortized over the life of the debenture. The Trust's obligation to make scheduled payments of principal and interest constitutes a financial liability under the revised standard and exists until the instrument is either converted or redeemed. The holders' option to convert the financial liability into trust units is an embedded conversion option. The effect of the adoption of this standard is presented in Note 4 to the financial statements. (ii) Foreign currency translation In the fourth quarter of 2004, the Trust reviewed its practices for U. S. operations and determined that such operations are self-sustaining as a result of the development of the Trust's management practices for U.S. operations. The accounts of self-sustaining foreign operations are translated using the current rate method, whereby assets and liabilities are translated at period-end exchange rates, while revenues and expenses are translated using rates for the period. Translation gains and losses related to the operations are deferred and included as a separate component of unitholders' equity. Previously, operations outside of Canada were considered to be integrated and translated using the temporal method. Under the temporal method, monetary assets and liabilities were translated at the period end exchange rates, other assets and liabilities at the historical rates and revenues and expenses at the rates for the period except depreciation, depletion and accretion, which were translated on the same basis as the related assets. This change in practice was adopted prospectively beginning October 1, 2004. 3. Acquisitions Acquisition of Nautilus On March 2, 2005 Provident acquired Nautilus Resources, LLC ("Nautilus") for cash consideration of $90.2 million and acquisition costs of $1.2 million. Nautilus was a private oil and gas exploration and production company active in Wyoming, USA. The transaction has been accounted for using the purchase method with the allocation of the purchase price as follows:
Net assets acquired and liabilities assumed
Property, plant and equipment $ 99,877
Working capital 1,237
Asset retirement obligation (1,557)
Non-hedging derivative instrument (8,137)
---------------------------------------------------------------------
$ 91,420
---------------------------------------------------------------------
---------------------------------------------------------------------
Consideration
Acquisition costs $ 1,237
Cash 90,183
---------------------------------------------------------------------
$ 91,420
---------------------------------------------------------------------
---------------------------------------------------------------------
4. Long-term debt
As at As at
March 31, 2005 Dec 31, 2004
---------------------------------------------------------------------
Revolving term credit facility $ 173,250 $ 262,750
Convertible debentures 257,405 169,456
---------------------------------------------------------------------
$ 430,655 $ 432,206
---------------------------------------------------------------------
---------------------------------------------------------------------
(i) Revolving term credit facility At March 31, 2005 and December 31, 2004 Provident had a $410.0 million term credit facility. At March 31, 2005 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 49.8 percent. The guarantees totaled $31.0 million at December 31, 2004. (ii) Convertible debentures On March 1, 2005 the Trust issued $100.0 million of unsecured convertible subordinated debentures ($95.8 million net of issue costs) with a 6.5 percent coupon rate maturing August 31, 2012. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $13.75 per trust unit prior to August 31, 2012 and may be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded at fair value $91.8 million The difference between the fair value and proceeds of $8.2 was recorded as equity. The face value for these instruments as at March 31, 2005 was $100.0 million. On July 6, 2004 the Trust issued $50.0 million of unsecured subordinated convertible debentures ($48.0 million net of issue costs) with an eight percent coupon rate maturing July 31, 2009. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $12.00 per trust unit prior to July 31, 2009, and may be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded fair value of $48.1 million under accounting rules. The difference between the fair value and proceeds of $1.9 million was recorded as equity. The face value for these instruments as at March 31, 2005 was $50.0 million. On September 30, 2003 the Trust issued $75 million of unsecured subordinated convertible debentures ($71.8 million net of issues costs) with an 8.75 percent coupon rate maturing December 31, 2008. Issue costs have been classified as deferred financing charges. The debentures may be converted into trust units at the option of the holder at a conversion price of $11.05 per trust unit prior to December 31, 2008, and may be redeemed by the Trust under certain circumstances. The unsecured subordinated convertible debentures were initially recorded at fair value under accounting rules of $70.6 million. The difference between the fair value and proceeds of $4.4 million was recorded as equity. The face value for these instruments as at March 31, 2005 was $74.1 million. 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 face value for these instruments as at March 31, 2005 was $45.7 million. The Trust may elect to satisfy interest and principal obligations by the issuance of trust units. During the period ended March 31, 2005, $5.5 million of debentures were converted to trust units at the election of debenture holders (2004 - nil). The following tables details each convertible debenture:
($000s except
conversion As at As at
pricing) March 31, 2005 Dec 31, 2004
---------------------------------------------------------------------
Conversion
Price
Carrying Carrying per
Value Face Value Face Maturity unit
(1) Value (1) Value Date (2)
---------------------------------------------------------------------
6.5%
Convertible Aug. 31,
Debentures $ 91,896 $100,000 $ - $ - 2012 13.75
8.0%
Convertible July 31,
Debentures 48,732 50,000 48,199 50,000 2009 12.00
8.75%
Convertible Dec. 31,
Debentures 71,143 74,117 71,834 74,930 2008 11.05
10.5%
Convertible May 15,
Debentures 45,634 45,673 49,423 49,881 2007 10.70
----------------------------------------------------
$257,405 $269,790 $169,456 $174,811
----------------------------------------------------
----------------------------------------------------
(1) Excluding equity component of convertible debentures
(2) The debentures may be converted into trust units at the option of
the holder of the Trust at the conversion price per unit
5. Asset retirement obligation The Trust's asset retirement obligation is based on the Trust's net ownership in wells, facilities and the midstream assets and represents management's estimate of the costs to abandon and reclaim those wells, facilities and midstream assets as well as an estimate of the future timing of the costs to be incurred. Estimated cash flows have been discounted at the Trust's credit-adjusted risk free rate of seven percent and an inflation rate of two percent. The total undiscounted amount of future cash flows required to settle asset retirement obligations related to oil and gas operations is estimated to be $140.7 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.
Quarter ended March 31,
------------------------
2005 2004
------------------------
Carrying amount, beginning of period $ 40,506 $ 33,182
Liabilities assumed on corporate acquisitions 1,557 -
Liabilities incurred during the period 121 329
Accretion expense 795 580
Settlement of liabilities during the period (629) (1,068)
---------------------------------------------------------------------
Carrying amount, end of period $ 42,350 $ 33,023
---------------------------------------------------------------------
---------------------------------------------------------------------
6. Unitholders contributions and exchangeable shares The Trust has authorized capital of an unlimited number of common voting trust units. On March 1, 2005 the Trust issued 8.4 million units at $12.00 per unit for proceeds of $100.8 million ($95.6 million net of issue costs) pursuant to a February 18, 2005 public offering. On 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.
Quarter ended March 31,
--------------------------------------------------
2005 2004
--------------------------------------------------
Trust Units Number Amount Number Amount
of Units (000s) of Units (000s)
--------------------------------------------------
Balance at
beginning
of period 142,226,248 $ 1,438,393 82,824,688 $ 803,299
Issued for cash 8,400,000 100,800 4,500,000 50,400
Exchangeable share
conversions 1,344,888 12,806 240,838 2,077
Issued pursuant to
unit option plan 1,109,544 11,507 120,535 917
Issued pursuant to
the distribution
reinvestment plan 257,530 2,921 297,274 3,230
To be issued pursuant
to the distribution
reinvestment plan 132,000 1,508 131,417 1,374
Debenture conversions 466,933 5,479 2,336 25
Unit issue costs - (5,189) - (2,678)
---------------------------------------------------------------------
Balance at end
of period 153,937,143 $ 1,568,225 88,117,088 $ 858,644
---------------------------------------------------------------------
---------------------------------------------------------------------
Quarter ended March 31,
--------------------------------------------------
2005 2004
--------------------------------------------------
Exchangeable
shares
Provident Number Amount Number Amount
Acquisitions Inc. of Units (000s) of Units (000s)
--------------------------------------------------
Balance at
beginning
of period 336,876 $ 3,675 534,357 $ 5,829
Converted to
trust units (336,876) (3,675) (190,299) (2,077)
---------------------------------------------------------------------
Balance, end of
period - - 344,058 3,752
Exchange ratio,
end of period - 1.29351
---------------------------------------------------------------------
Trust units issuable
upon conversion,
end of period - $ - 445,042 $ 3,752
---------------------------------------------------------------------
---------------------------------------------------------------------
Exchangeable
shares
Provident Number Amount Number Amount
Energy Ltd. of Units (000s) of Units (000s)
--------------------------------------------------
Balance at
beginning
of period 638,474 $ 6,833 1,279,227 $ 13,689
Issued to acquire
Provident Management
Corp. - - - -
Converted to trust
units - - - -
---------------------------------------------------------------------
Balance, end of period 638,474 6,833 1,279,227 13,689
Exchange ratio,
end of period 1.39162 1.22632
---------------------------------------------------------------------
Trust units issuable
upon conversion,
end of period 888,513 $ 6,833 1,568,742 $ 13,689
---------------------------------------------------------------------
---------------------------------------------------------------------
Exchangeable
shares (Series B)
Provident Number Amount Number Amount
Energy Ltd. of Units (000s) of Units (000s)
--------------------------------------------------
Balance at
beginning
of period 2,095,271 $ 23,931 - $ -
Converted to
trust units (799,495) (9,131) - -
---------------------------------------------------------------------
Balance, end
of period 1,295,776 14,800 - -
Exchange ratio,
end of period 1.09979 -
---------------------------------------------------------------------
Trust units issuable
upon conversion,
end of period 1,425,081 $ 14,800 - $ -
---------------------------------------------------------------------
---------------------------------------------------------------------
Total Trust unit
issuable upon
conversion of all
exchangeable
shares, end of
period 2,313,594 21,633 2,013,784 $ 17,441
---------------------------------------------------------------------
---------------------------------------------------------------------
The per trust unit amounts for 2005 were calculated based on the weighted average number of units outstanding of 149,205,605 which includes the shares exchangeable into trust units (2004 - 88,040,817). The diluted per trust unit amounts for 2005 are calculated at 332,062 trust units (2004 - 142,594) for the effect of the unit option plan. These additional units have been excluded in the dilution calculation as their effect is anti-dilutive when applied against the net losses of both periods. Provident's convertible debentures are excluded in the computation of diluted earnings per unit as their effect is anti-dilutive.
7. Revenue
Quarter ended March 31,
2005 2004
------------------------
Gross production revenue $ 134,594 $ 79,952
Product sales and service revenue 244,863 201,425
Royalties (23,334) (15,245)
---------------------------------------------------------------------
Revenue $ 356,123 $ 266,132
---------------------------------------------------------------------
---------------------------------------------------------------------
Realized loss on financial derivative
instruments $ (10,338) $ (9,656)
Unrealized loss on financial derivative
instruments (23,762) (22,044)
---------------------------------------------------------------------
$ 322,023 $ 234,432
---------------------------------------------------------------------
---------------------------------------------------------------------
Change in unrealized loss on financial
derivative instruments $ (23,373) $ (15,452)
Amortization of loss on financial derivative
instruments (note 11) (389) (6,592)
---------------------------------------------------------------------
Unrealized loss on financial derivative
instruments $ (23,762) $ (22,044)
---------------------------------------------------------------------
---------------------------------------------------------------------
The realized loss on financial derivative instruments for the period ended March 31, 2005 of $10.3 million (2004 - $9.7 million realized loss) relates to the cash settlement on derivative instruments. 8. 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.
Quarter ended March 31,
------------------------------------------
2005 2004
------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
------------------------------------------
Outstanding,
beginning of period 5,200,331 $11.01 4,008,744 $11.06
Granted 195,200 11.55 211,750 10.86
Exercised (1,109,544) 10.93 (120,535) 10.96
Cancelled (500) 10.95 (13,500) 10.90
---------------------------------------------------------------------
Outstanding, end of period 4,285,487 11.06 4,086,459 11.06
---------------------------------------------------------------------
Exercisable, end of period 2,303,673 $11.11 2,179,863 $11.08
---------------------------------------------------------------------
---------------------------------------------------------------------
At March 31, 2005, the Trust had 4,285,487 options outstanding with strike prices ranging between $8.40 and $12.39 per unit. The weighted average remaining contractual life of the options is 2.70 years and the weighted average exercise price is $11.06 per unit excluding average potential reductions to the strike prices of $0.98 per unit. At March 31, 2004, the Trust had 4,086,459 options outstanding with strike prices ranging between $8.40 and $12.39 per unit. The weighted average remaining contractual life of the options is 2.92 years and the weighted average exercise price is $11.06 per unit excluding average potential reductions to the strike prices of $1.30 per unit. On December 31, 2004 the Trust prospectively applied the fair value based method of accounting for the Plan. Previously, the Trust applied the intrinsic value methodology due to the uncertainties of future expected distributions. The Trust now uses the Black-Scholes option-pricing model to calculate the estimated fair value of the outstanding options issued on or after January 1, 2003 at their issue date. The Trust has reevaluated the assumptions required to calculate the fair value of options and considers the estimates required to calculate the fair value reasonably estimated at the time of the issue of the options. In 2005 the Trust recorded unit-based compensation (non-cash general and administrative) of $0.3 million, for the 5.5 million options granted on or after January 1, 2003 (2004 - $1.2 million). As at March 31, 2005, the following assumptions are the weighted averages of the individual assumptions applied at each grant date to arrive at an estimate of fair value of all granted options on or after January 1, 2003 of $3.8 million:
Quarter ending For the year ending
March 31, 2005 Dec 31 2004 Dec 31 2003
---------------------------------------------------------------------
Expected annual dividend 8.00% 8.00% 8.00%
Expected volatility 20.27% 20.18% 19.46%
Risk - free interest rate 3.24% 3.30% 3.66%
Expected life of option (yrs) 3.31 3.31 3.31
Expected forteitures - - -
Fair Value of Granted
Options $0.2 million $1.2 million $2.4 million
---------------------------------------------------------------------
---------------------------------------------------------------------
The following table reconciles the movement in the contributed
surplus balance:
Quarter ended March 31,
2005 2004
------------------------
Contributed surplus, beginning of the period $2,002 $1,305
Compensation expense (recovery) 256 (419)
Benefit on options exercised charged to
unitholders' equity (652) (16)
---------------------------------------------------------------------
Contributed surplus, end of the period $1,606 $870
---------------------------------------------------------------------
---------------------------------------------------------------------
(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 UAR - Unattended Radar UAR - Unconventional Assisted Recovery UAR - Uniformly At Random UAR - Unión Argentina de Rugby (Argentinian Rugby League) UAR - Union of African Railways UAR - Unit Airman Record UAR - United Arab Republic UAR - Unstable Ape Records (Australian independent record label) UAR - Upper Austrian Research UAR - Utah Association of Realtors's") which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units. UAR's vest evenly over a period of three years commencing one year after grant and expire after four years. The UAR's, upon vesting, provide certain employees entitlement to receive a cash payment equal to the excess of the market price of the Trust's Units over the exercise price of the right less notionally accrued distributions in excess of an eight percent return. The following table summarizes the information about UAR's
As at
March 31, 2005
---------------------------------------
Number of Units Weighted Average
Appreciation Rights Exercise Price
-------------------- -----------------
Outstanding beginning of year 976,000 $9.59
Granted -
Exercised - -
Cancelled - -
---------------------------------------------------------------------
Outstanding, end of quarter 976,000 $9.59
---------------------------------------------------------------------
Exerciseable, end of quarter -
---------------------------------------------------------------------
---------------------------------------------------------------------
Weighted average remaining contract life 3.23
Average reductions to exercise price $0.44
---------------------------------------------------------------------
---------------------------------------------------------------------
The fair value associated with the UAR's is expensed in the statement of income over the vesting period. During the period, the Trust recorded compensation costs of $0.4 million with respect to the outstanding UAR's (2004 - nil).
9. Reconciliation of cash flow and distributions
Quarter ended March 31,
2005 2004
------------------------
Cash provided by operating activities $ 58,707 $ 44,005
Change in non cash working capital 4,801 (8,804)
Site restoration expenditures 629 1,068
---------------------------------------------------------------------
Cash flow from operations 64,137 36,269
Cash reserved for financing and investing
activities (12,403) (5,233)
---------------------------------------------------------------------
Cash distributions to unitholders 51,734 31,036
Accumulated cash distributions,
beginning of period 412,646 248,018
---------------------------------------------------------------------
Accumulated cash distributions,
paid and declared, end of period $ 464,380 $ 279,054
---------------------------------------------------------------------
Cash distributions per unit $ 0.36 $ 0.36
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash reserved for financing and investing activities is a discretionary amount and represents the difference between cash flow from operations less distributions. 10. Financial instruments and hedging 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, January 1, 2005 $ 2,144 Derivative instruments amortized (389) --------------------------------------------------------------------- Deferred derivative loss, March 31, 2005 $ 1,755 --------------------------------------------------------------------- --------------------------------------------------------------------- 11. Subsequent Event On April 26, 2005 Provident announced its intention to redeem the aggregate amount of all outstanding 10.50 percent convertible unsecured subordinated debentures as of May 31, 2005 at an amount of $1,050 plus all accrued and unpaid interest hereon to May 30, 2005 per each $1,000 principal amount of debentures. At the option of the holder, each debenture is convertible into fully paid and non-assessable trust units at a price of $10.70 per trust unit at any time prior to 4:30pm (MDT) on May 30, 2005. The conversion rate is 93.4579 trust units per $1,000 principal amount of debentures. The debentures were originally issued to fund an acquisition of petroleum and natural gas assets and for general corporate purposes and were issued with a term that would have them mature on June 15, 2007. 12. Comparative balances Certain comparative numbers have been restated to conform to the current period's presentation. 13. Segmented information The Trust's business activities are conducted through three business segments: Canadian oil and natural gas production, United States oil and natural gas production and midstream services and marketing. Oil and natural gas production in Canada and the United States includes exploitation, development and production of crude oil and natural gas reserves. Midstream services and marketing includes fractionation, transportation, loading and storage of natural gas liquids, and marketing of crude oil and natural gas liquids. Geographically the Trust operates in Canada and the USA in the oil and gas production business segment. The geographic components have been presented as well as the midstream and marketing business that operates in Canada. Interest and long-term debt have been allocated to the business segments on the basis of invested capital at net book value.
Quarter ended March 31, 2005
---------------------------------------
United
Canada States Total
Oil and Oil and Oil and
Natural Gas Natural Gas Natural Gas
Production Production Production
------------ ----------- ------------
Revenue
Gross production revenue $ 105,563 $ 29,031 $ 134,594
Royalties (20,669) (2,665) (23,334)
Product sales and service
revenue - - -
Realized gain/(loss) on
financial derivative
instruments (8,459) (2,354) (10,813)
---------------------------------------------------------------------
76,435 24,012 100,447
Expenses
Cost of goods sold - - -
Production, operating and
maintenance 25,620 7,426 33,046
Transportation 1,692 - 1,692
Foreign exchange (gain) loss 743 (550) 193
General and administrative 4,483 1,771 6,254
---------------------------------------------------------------------
32,538 8,647 41,185
---------------------------------------------------------------------
Earnings before interest, taxes,
depletion, depreciation,
accretion and non-cash revenue 43,897 15,365 59,262
Non-cash revenue
Unrealized gain/(loss) on
financial derivative
instruments (12,091) (11,138) (23,229)
Amortization of gain/(loss)
on financial derivative
instruments (389) - (389)
---------------------------------------------------------------------
(12,480) (11,138) (23,618)
---------------------------------------------------------------------
Other expenses
Depletion, depreciation and
accretion 41,552 5,107 46,659
Interest on bank debt 2,111 705 2,816
Interest & accretion on
convertible debentures 3,560 1,191 4,751
Amortization of deferred
financing charges 57 19 76
Unrealized foreign exchange
(gain) loss - 142 142
Non-cash general and
administrative 256 375 631
Capital taxes 1,377 - 1,377
Current and withholding taxes - 2,367 2,367
Future income tax expense
(recovery) (7,720) - (7,720)
---------------------------------------------------------------------
41,193 9,906 51,099
Non-controlling interest loss - (105) (105)
---------------------------------------------------------------------
Net income (loss) for the
period $ (9,776) $ (5,574) $ (15,350)
---------------------------------------------------------------------
---------------------------------------------------------------------
Midstream Inter-
Services and segment
Marketing Elimination Total
------------ ----------- ------------
Revenue
Gross production revenue $ - $ - $ 134,594
Royalties - - (23,334)
Product sales and service
revenue 322,084 (77,221) 244,863
Realized gain/(loss) on
financial derivative
instruments 475 - (10,338)
---------------------------------------------------------------------
322,559 (77,221) 345,785
Expenses
Cost of goods sold 296,841 (77,221) 219,620
Production, operating and
maintenance 7,375 - 40,421
Transportation - - 1,692
Foreign exchange (gain) loss (60) - 133
General and administrative 2,023 8,277
---------------------------------------------------------------------
306,179 (77,221) 270,143
---------------------------------------------------------------------
Earnings before interest, taxes,
depletion, depreciation,
accretion and non-cash revenue 16,380 - 75,642
Non-cash revenue
Unrealized gain/(loss) on
financial derivative
instruments (144) - (23,373)
Amortization of gain/(loss) on
financial derivative
instruments - - (389)
---------------------------------------------------------------------
(144) - (23,762)
---------------------------------------------------------------------
Other expenses
Depletion, depreciation and
accretion 2,502 - 49,161
Interest on bank debt 510 - 3,326
Interest & accretion on
convertible debentures 861 - 5,612
Amortization of deferred
financing charges 14 - 90
Unrealized foreign exchange
(gain) loss (162) - (20)
Non-cash general and
administrative - - 631
Capital taxes - - 1,377
Current and withholding taxes - - 2,367
Future income tax expense
(recovery) - - (7,720)
---------------------------------------------------------------------
3,725 - 54,824
Non-controlling interest loss - - (105)
---------------------------------------------------------------------
Net income (loss) for the
period $ 12,511 $ - $ (2,839)
---------------------------------------------------------------------
---------------------------------------------------------------------
Quarter ended March 31, 2005
---------------------------------------
United
Canada States Total
Oil and Oil and Oil and
Natural Gas Natural Gas Natural Gas
Production Production Production
------------ ----------- ------------
Selected balance sheet items
Capital Assets
Property, plant and equipment
net $ 736,719 $ 363,584 $1,100,303
Goodwill 330,944 - 330,944
Capital Expenditures
Property, plant and equipment
net 14,049 14,884 28,933
Property, plant and equipment
through corporate
acquisitions - 99,877 99,877
Goodwill additions - -
Working capital
Accounts receivable 89,638 16,841 106,479
Petroleum product inventory - - -
Accounts payable and accrued
liabilities 117,172 28,402 145,574
Long-term debt $ 274,112 $ 90,868 $ 364,980
---------------------------------------------------------------------
---------------------------------------------------------------------
Midstream Inter-
Services and segment
Marketing Elimination Total
------------ ----------- ------------
Selected balance sheet items
Capital Assets
Property, plant and equipment
net $ 279,452 $ - $1,379,755
Goodwill - - 330,944
Capital Expenditures
Property, plant and equipment
net 153 - 29,086
Property, plant and equipment
through corporate
acquisitions - 99,877
Goodwill additions - - -
Working capital
Accounts receivable 81,220 (16,088) 171,611
Petroleum product inventory 14,717 - 14,717
Accounts payable and accrued
liabilities 63,866 (16,088) 193,352
Long-term debt $ 65,675 $ - $ 430,655
---------------------------------------------------------------------
---------------------------------------------------------------------
Quarter ended March 31, 2004 (1)
------------------------------------------------
Canada Midstream
Oil and Services Inter-
Natural Gas and segment
Production Marketing Elimination Total
------------ --------- ----------- ----------
Revenue
Gross production
revenue $ 79,952 $ - $ - $ 79,952
Royalties (15,245) - - (15,245)
Product sales and
service revenue - 232,845 (31,420) 201,425
Realized gain/(loss)
on financial
derivative
instruments (9,842) 186 - (9,656)
---------------------------------------------------------------------
54,865 233,031 (31,420) 256,476
Expenses
Cost of goods sold - 211,441 (31,420) 180,021
Production, operating
and maintenance 18,504 9,044 - 27,548
Transportation 1,234 - - 1,234
Foreign exchange gain - (515) - (515)
General and
administrative 4,386 864 - 5,250
---------------------------------------------------------------------
24,124 220,834 (31,420) 213,538
---------------------------------------------------------------------
Earnings before
interest, taxes,
depletion,
depreciation,
accretion and
non-cash revenue 30,741 12,197 - 42,938
Non-cash revenue
Unrealized loss on
financial derivative
instruments (14,394) (1,058) - (15,452)
Amortization of loss
on financial
derivative
instruments (6,592) - - (6,592)
---------------------------------------------------------------------
(20,986) (1,058) - (22,044)
---------------------------------------------------------------------
Other expenses
Depletion,
depreciation and
accretion 32,153 2,296 - 34,449
Interest on bank debt 1,024 1,120 - 2,144
Interest & accretion
on convertible
debentures 2,772 1,277 - 4,049
Amortization of
deferred financing
charges 237 122 - 359
Unrealized foreign
exchange (gain) loss - - - -
Non-cash general and
administrative (384) (35) - (419)
Capital taxes 895 110 - 1,005
Current and
withholding taxes - - - -
Future income tax
expense (recovery) (16,939) 2,390 - (14,549)
---------------------------------------------------------------------
19,758 7,280 - 27,038
Non-controlling
interest - -
---------------------------------------------------------------------
Net income (loss) for
the period $ (10,003) $ 3,859 $ - $ (6,144)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2
Quarter ended March 31, 2004 (1)
------------------------------------------------
Midstream
Oil and Services Inter-
Natural Gas and segment
Production Marketing Elimination Total
------------ --------- ----------- ----------
Selected balance
sheet items
Capital Assets
Property, plant and
equipment net $ 584,720 $ 277,977 $ - $ 862,697
Goodwill 102,443 - - 102,443
Capital Expenditures
Property, plant and
equipment net 9,289 539 - 9,828
Property, plant and
equipment through
corporate
acquisitions - - - -
Goodwill additions - - - -
Working capital
Accounts receivable 46,021 99,099 (12,840) 132,280
Petroleum product
inventory - 14,037 - 14,037
Accounts payable
and accrued
liabilities 57,863 91,261 (12,840) 136,284
Long-term debt $ 200,022 $ 102,721 $ - $ 302,743
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Restated - note 2
Provident Energy Trust (TSX:PVE.UN) (AMEX:PVX) |
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