Provident Energy Announces 2003 Year-End and Fourth Quarter Results.Business Editors CALGARY, Alberta--(BUSINESS WIRE)--March 18, 2004 Provident Energy Trust (TSX:PVE.UN) (AMEX:PVX): 2003 Highlights -- Provident was the first energy trust to adopt and execute a balanced portfolio strategy and diversify into energy infrastructure with the acquisition of the Redwater Natural Gas Liquids (NGL) Processing System. As a result, Provident's economic life as a measure of future cash flows has been significantly extended beyond that which is typically measured by the reserve life of Provident's oil and natural gas assets. -- Provident closed the largest single bought deal financing within the conventional oil and natural gas trust sector raising net proceeds of $262.9 million to finance the Redwater acquisition. -- Provident Midstream Services, a long-life stable source of cash flow, produced earnings before interest, taxes and depreciation (EBITDA) of $10.2 million and cash flow of $9.0 million in the fourth quarter, on target with expectations. -- Provident achieved a 95 percent success rate in its drilling program, adding approximately 3,200 boed of initial production at a cost of approximately $8,800 per flowing boe. -- Provident realized minimal impact to its reserves from the adoption of NI-51-101. Before accounting for production, proved plus probable reserves when compared to established reserves reported on January 1, 2003 were virtually flat, as were year over year comparisons of proved developed producing reserves. -- Provident delivered $2.06 per unit in cash distributions and generated a total return of 25 percent for its unitholders. -- Provident has earned a total return of 58 percent for its unitholders from inception March 6, 2001 to December 31, 2003. The total return includes $6.63 of cash distributions. All values are in Canadian dollars and conversions of natural gas volumes to barrels of oil equivalent (boe) are at 6:1 unless otherwise indicated. Provident Energy Trust (Provident) (TSX - PVE.UN; AMEX-PVX) reported 2003 cash flow from operations of $135.7 million ($1.98 per unit) compared to $97.0 million ($2.41 per unit) in 2002. Distributions declared in 2003 totaled $129.6 million ($2.06 per unit) compared to $81.5 million ($2.03 per unit) in 2002. For the year, Provident generated a total return of 25 percent, including cash distributions and unit capital appreciation. From inception March 6, 2001 to December 31, 2003, Provident's total return to unitholders has been 58 percent. The total return includes $6.63 of cash distributions. "2003 was a defining year for Provident Energy. As a result of our decision to implement a balanced portfolio strategy, diversify into the midstream services business, and acquire the Redwater NGL Processing System, we are a stronger energy trust. Our asset base is more diversified. Our cash flow and distributions are more stable. And we are now very well positioned to deliver long-term value to investors," said Chief Executive Officer Tom Buchanan. "Provident is unique among Canadian energy trusts given we have two solid platforms for accretive growth in our oil and natural gas production business and our midstream services business," Buchanan said. In 2003, Provident maintained a high annual payout ratio. Provident believes cash flow remaining after debenture interest and capital obligations should be distributed to unitholders. In 2003, Provident paid out all of its adjusted cash flow as the Trust was able to satisfy its $31.6 million capital program requirements with funds from its distribution reinvestment programs and minor property divestitures. Fourth quarter 2003 cash flow from operations was $33.3 million ($.41 per unit) compared to $36.3 million ($.63 per unit) in fourth quarter 2002. Distributions declared in fourth quarter 2003 totaled $32.0 million ($.39 per unit) compared to $30.0 million ($0.57 per unit) in 2002. Business Unit Results Midstream Services On September 30, Provident completed the acquisition of the Redwater NGL Processing System (Redwater) from Williams Energy Canada for $283.2 million and $15.4 million in inventory. In conjunction with the Redwater acquisition, Provident closed the largest bought deal financing within the conventional oil and natural gas trust sector for total net proceeds of approximately $262.9 million. The financing included a total issuance of 19.2 million trust units at a price of $10.50 per trust unit and $75.0 million of five-year 8.75 percent convertible unsecured subordinated debentures. Provident's Redwater assets comprise the most modern and lowest-cost-NGL processing system of its kind in western Canada. Located in one of the four main North American NGL hubs, Redwater accounts for 30 percent of the NGL fractionation capacity in Western Canada and is an important asset in the future of Canada's oil and natural gas business. The long-life nature of the assets combined with long-term fee-based and fixed-margin contracts make it an ideal investment for an energy trust. From September 30 to December 31, 2003, Midstream Services generated EBITDA of $10.2 million and $9.0 million of cash flow. There is no comparable period given the fourth quarter of 2003 is the first quarter of recorded contribution from the Midstream Services business unit. In 2004, the midstream services business is forecast to account for 25 to 30 percent of Provident's cash flow. "One of the highlights for Provident in 2003 was our acquisition of the Redwater NGL Processing System," said Randy Findlay, president of Provident. "A world-class asset, Redwater is a long-life physical asset with long-term fee-for-service and fixed-margin contracts. The midstream investment complements our oil and natural gas production business (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.) and enhances the stability of Provident's cash flow and distributions." Oil and Gas Production (OGP) 2003 cash flow from the OGP business unit was $126.7 million compared to $97.0 million in 2002. During the fourth quarter 2003, cash flow from OGP was $24.4 million compared to $36.3 million for the year ago period. In 2003, Provident achieved a 95 percent success rate in its drilling program, adding approximately 3,200 boed of initial production at a cost of approximately $8,800 per flowing boe. Of the 3,200 boed, 2,650 boed was added in the Lloydminster Lloydminster (loid`mĭnstər), city (1991 pop. in Alberta, 10,042; in Saskatchewan, 7,241), on the Alta.-Sask. boundary, Canada. The city is chartered by both provinces. Farming and ranching are the chief activities of the region, which has oil, natural gas, coal, and salt deposits. area and the remaining balance was added in Southern Alberta. Provident's total capital program in 2003 was $31.6 million, of which $7.5 million was spent in the fourth quarter. In the fourth quarter 300 boed of initial production was added. "In 2003, we were very pleased with the results we achieved in our heavy oil drilling program," said Findlay. "In 2004, we will build upon this platform of success. Accordingly, we have increased our capital budget by 45 percent to $46 million and have launched expanded internal development efforts to include shallow gas opportunities in our core regions of Southern Alberta and Saskatchewan and heavy oil plays around Lloydminster." Although average annual production increased from 21,801 boed in 2002 to 27,314 boed in 2003, Provident fell short of its average daily production goal of 28,500 boed. The shortfall was mainly due to higher natural gas declines at both its Brazeau and Gilby fields, project deferrals, and the fact the Trust chose not to complete a significant oil and natural gas acquisition. Average production in the fourth quarter 2003 was 26,193 boed compared to 30,790 boed for the same period in 2002. Provident's 2003 daily production mix was weighted 46 percent natural gas, 29 percent light/medium oil and NGLs, and 25 percent heavy oil. Field netbacks of $15.19 per boe in 2003 were flat year over year primarily due to higher operating costs and opportunity costs Opportunity Cost 1. The cost of an alternative that must be forgone in order to pursue a certain action. Put another way, the benefits you could have received by taking an alternative action.2. The difference in return between a chosen investment and one that is necessarily passed up. Say you invest in a stock and it returns a paltry 2% over the year. associated with Provident's Commodity Price Risk Management Program. In 2003, the oil and natural gas sector generally realized increased costs due to higher costs for processing, propane, electricity, well servicing and workovers. Provident's operating costs increased from $6.63 per boe in 2002 to $7.66 per boe in 2003. During the fourth quarter, Provident's operating costs were $8.99 per boe compared to $6.52 per boe for the year ago period. An increase in fourth quarter 2003 operating costs includes non-operated property expenses prior to September 30, 2003 as well as adjustments to adequately account for expenses that should be recorded and classified in the 2003 year-end. Provident has already initiated a number of activities to effectively control operating costs including reorganization of operating teams. For 2004, Provident expects operating costs to average between $7.50 to $8.00 per boe. Provident's Commodity Price Risk Management Program (CPRMP) involves a disciplined hedging strategy and use of derivative instruments to minimize price risk associated with the volatility of commodity prices. Strategies are selected based on their ability to help Provident provide stable cash flow and distributions per unit rather than to simply lock in a specific price per barrel of oil or cubic foot of natural gas. In 2003, Provident realized an opportunity cost of $48.9 million ($0.73 per unit) in 2003 compared to $6.5 million in 2002 ($0.16 per unit). In 2003, 46 percent ($22.6 million) of Provident's opportunity cost was incurred in the first quarter. During this period, world commodity spot prices were pushed higher than the prices at which Provident had hedged during the fourth quarter of 2002. The spot price increase was primarily due to market perception of a supply shortage created by a petroleum worker strike in Venezuela and reduced exports from the Gulf resulting from the U.S. invasion of Iraq. In the fourth quarter of 2003, opportunity costs were $4.9 million compared to $4.0 million in the same period for 2002. While in 2003 Provident experienced opportunity costs, the Trust remains committed to its CPRMP. Provident's hedging program achieved its goal of stabilizing cash flows. At the same time it allowed Provident to capture the higher commodity prices realized in the market during 2003 on a significant portion of its production that was not hedged. Over the long term, we believe a disciplined and consistent approach to commodity price risk management will provide for a more predictable range of distributions. Reserves Provident's oil and natural gas reserves as of January 1, 2004 were evaluated and reviewed by McDaniel and Associates (McDaniel). McDaniel evaluated the properties that comprised approximately 75 percent of the value of the Trust with the properties making up the remaining 25 percent evaluated by qualified Provident staff and ultimately reviewed by McDaniel. The evaluation report used McDaniel's price forecast at January 1, 2004 and is prepared in accordance with new disclosure standards as mandated by the Canadian Securities Administrators' National Instrument 51-101 (NI-51-101) Standards of Disclosure for Oil and Gas Activities. Under McDaniel's NI-51-101 evaluation Provident had minimal revisions to its reserves on a company interest basis. Before accounting for production, proved plus probable reserves when compared to established reserves reported on January 1, 2003 were virtually flat, as were year over year comparisons of proved developed producing reserves. The proved plus probable reserve category was revised upward by 1.0 percent while proved developed producing reserves had a downward revision of 1.5 percent. The total proved reserves category was revised downward by 5.6 percent primarily as a result of competitive drainage at the Brazeau and Gilby natural gas fields. Year over year, Provident realized a 3.0 percent increase in its proved developed reserves as a percent of total proved reserves from 82 percent as reported in 2003 to 85 percent as reported in 2004. Provident also had three-year average total proved and probable finding, development and acquisition (FD&A) costs of $12.77 per boe, including future development costs (FDC) and NI-51-101 revisions. Production in 2003 totaled 9,970 Mboe and along with, additions and revisions, resulted in a proved plus probable reserves opening balance at January 1, 2004 of 54,894 Mboe compared to 64,501 Mboe on January 1, 2003. Based on McDaniel's evaluation, Provident's total proved plus probable reserve life index (RLI) for its oil and natural gas assets was 6.6 years at January 1, 2004 compared to 6.7 years reported a year ago. The RLI was determined by applying the average 2004 production rate from the McDaniel's evaluation to the remaining volumes as of January 1, 2004. The results of McDaniel's evaluation are summarized in the tables included in the Management Discussion and Analysis. It is important to note that as a result of the addition of long-term, stable cash flow from the midstream services business, Provident's economic life as a measure of future cash flows has been significantly extended beyond that which is typically measured by the reserve life of Provident's oil and natural gas assets. To assist with quarter over quarter analysis, Provident has made available on its website its fourth quarter income statement and statement of cash flows. Provident senior management will discuss 2003 year end results on a conference call at 8:00 a.m. MT / 10:00 a.m. ET on Friday, March 19. The conference call may be accessed by dialing 416-405-9328 in the Toronto area and 1-800-387-6216 for all other areas of Canada and the United States. Please request the Provident conference call, reservation no. 3017776. Please call in five to 10 minutes prior to the scheduled start time. A live webcast will also be available on Provident's website at www.providentenergy.com. A replay of the conference call will be stored until April 18 on Provident's website and by dialing 416-695-5800 or 1-800-408-3053 with passcode 3017776. 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. 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.
Financial highlights
Canadian dollars (000s except per unit amounts)
Quarter ended Year ended
December 31, December 31,
% %
2003 2002 Change 2003 2002 Change
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Revenue $212,610 $ 64,561 229 $473,571 $207,823 128
Cash flow from
operations $ 33,308 $ 36,299 (8) $135,706 $ 96,896 40
Per weighted
average unit
- basic $ 0.41 $ 0.63 (35) $ 1.98 $ 2.41 (18)
Declared
distributions to
unitholders $ 32,023 $ 30,080 6 $129,612 $ 81,526 59
Per unit $ 0.39 $ 0.57 (32) $ 2.06 $ 2.03 1
Net income (loss) $ 21,067 $ 7,033 200 $ 33,394 $ 8,340 300
Per weighted
average unit
- basic $ 0.22 $ 0.09 144 $ 0.38 $ 0.09 322
Per weighted
average unit
- diluted $ 0.22 $ 0.09 144 $ 0.38 $ 0.09 322
Capital
expenditures $ 7,549 $ 6,605 14 $ 31,628 $ 21,980 44
Acquisition of
businesses $ - $254,389 - $298,638 $356,963 (16)
Property
acquisitions $ - $ - - $ - $ 71,986 (100)
Property
dispositions $ - $ (5,651) - $ (9,947) $(11,157) (11)
Bank Debt $236,500 $187,200 26 $236,500 $187,200 26
Unitholders'
equity $679,228 $472,779 44 $679,228 $472,779 44
Weighted average
trust units and
exchangeable
shares
outstanding
(000s) 80,926 57,603 40 68,448 40,222 70
Operational highlights
Quarter ended Year ended
December 31, December 31,
% %
2003 2002 Change 2003 2002 Change
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Daily production
Light/medium crude
oil (bpd) 6,454 7,478 (14) 6,812 5,096 34
Heavy oil (bpd) 7,151 6,459 11 6,902 6,310 9
Natural gas liquids
(bpd) 1,145 1,558 (27) 1,167 1,030 13
Natural gas (mcf) 68,657 91,766 (25) 74,596 56,193 33
Oil equivalent
(boed)(1) 26,193 30,790 (15) 27,314 21,801 25
Average selling
price (2)
Light/medium crude
oil ($/bbl) $ 26.61 $ 35.26 (25) $ 29.09 $ 34.62 (16)
Heavy oil ($/bbl) $ 20.25 $ 18.66 9 $ 22.09 $ 20.02 10
Corporate oil
blend ($/bbl) $ 24.14 $ 30.08 (20) $ 25.57 $ 26.55 (4)
Natural gas
liquids ($/bbl) $ 34.48 $ 33.82 2 $ 35.87 $ 29.04 24
Natural gas
($/mcf) $ 5.48 $ 5.06 8 $ 5.71 $ 4.67 22
Oil equivalent
($/boe)(1) $ 27.99 $ 28.83 (3) $ 30.16 $ 27.29 11
Netback ($/boe)
(1)(2) $ 12.95 $ 16.26 (20) $ 15.19 $ 15.09 1
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(1) Provident reports barrels of oil equivalent production converting
natural gas to oil on a 6:1 basis
(2) Average selling price and operating netback exclude the non-cash
amortization of hedging gains but include the cash impact of the
Commodity Risk Management Program.
Management's Discussion and Analysis The following analysis provides a detailed explanation of Provident's operating results for the year ended December 31, 2003 compared to the year ended December 31, 2002 and should be read in conjunction with the audited consolidated financial statements of Provident. This disclosure contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Provident's control, including the impact of general economic conditions in Canada and the United States; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; increased competition; the lack of availability of qualified personnel or management; fluctuations in commodity prices; foreign exchange or interest rates; stock market volatility and obtaining required approvals of regulatory authorities. Provident's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking estimates and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking estimates will transpire or occur, or if any of them do so, what benefits, including the amounts of proceeds, that Provident will derive therefrom. All amounts are reported in Canadian dollars, unless otherwise stated. All conversions of natural gas to oil equivalent are on a 6:1 basis. Provident Energy Trust has diversified investments in certain segments of the energy value chain. Provident currently operates in two key business segments: crude oil and natural gas production and exploitation (OGP) and Midstream Services and Marketing (Midstream). Provident's OGP business unit produces crude oil and natural gas from five core areas in the western Canadian sedimentary basin while the Midstream business unit processes, markets, transports and offers storage of natural gas liquids at the Redwater facility and surrounding infrastructure located north of Edmonton, Alberta, and markets crude oil. This analysis commences with a summary of the consolidated financial and operating results followed by segmented reporting on the OGP business unit and the Midstream business unit. The reporting focuses on the financial and operating measurements management uses in making business decisions and evaluating performance.
Consolidated cash flow from operations and cash distributions
Three months ended Year ended
December 31 December 31,
2003 2002 2003 2002
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Revenue, Cash Flow and
Distributions
Revenue (net of royalties) $212,609 $64,561 $400,702 $163,508
Cash flow from Operations $ 33,307 $36,298 $135,706 $ 96,896
Per weighted average unit
- basic(1) $ 0.41 $ 0.63 $ 1.98 $ 2.41
Interest on convertible
debentures $ (2,966) $(1,701) $ (7,341) $ (4,901)
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Adjusted cash flow $ 30,341 $34,597 $128,365 $ 92,085
Declared distributions $ 32,024 $30,080 $129,612 $ 81,526
Per Unit(2) $ 0.39 $ 0.57 $ 2.06 $ 2.03
Percent of cash flow
distributed 96% 83% 96% 84%
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Percent of adjusted cash flow
distributed 106% 87% 101% 89%
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(1) includes exchangeable shares
(2) excludes exchangeable shares
Cash flow from operations ("cash flow") increased 40 percent to $135.7 million in 2003 from $97.0 million in 2002. The growth in cash flow in 2003 reflected a full year of the oil and gas production acquisitions completed throughout 2002 as well as fourth quarter cash flow generated by the Midstream business unit acquired September 30, 2003. Cash flow from OGP increased 21 percent to $118.0 million compared to $97.0 million in 2002. The acquisition driven increase incorporated a 25 percent increase in production volumes, an increase in average commodity prices partially offset by opportunity costs from the Commodity Price Risk Management Program, lower realized prices due to the appreciating Canadian dollar, as well as increased general and administration costs and interest expense associated with Provident's growth. Cash flow from the Midstream business unit included in Provident's results effective September 30, 2003 totaled $9.0 million for the fourth quarter of 2003 with no comparable figure for 2002. Cash flow from operations per unit decreased 18 percent to $1.98 per unit compared to $2.41 in 2002. The opportunity cost associated with the Commodity Price Risk Management Program was significant in 2003 amounting to $0.71 per unit compared to the cost in 2002 of $0.16 per unit. Fourth quarter 2003 cash flow was $33.3 million, 8.3 percent below the $36.3 million of cash flow recorded in the fourth quarter of 2002. OGP 2003 fourth quarter cash flow was $24.3 million, 33 percent below the $36.3 million recorded in the comparable 2002 quarter. The main driver for this decrease was the 15 percent decrease in production volumes on a quarter over quarter basis. The lower production was the result of normal production declines partially offset by the volumes associated with Provident's 2003 capital program. The Midstream business unit added $9.0 million to fourth quarter 2003 cash flow with no comparable figure for the same quarter of 2002. Cash flow from operations per unit reflected the significant reduction in OGP production volumes and decreased 35 percent to $0.41 per unit compared to $0.63 per unit in the fourth quarter of 2002. Management uses cash flow (before changes in non-cash working capital) to analyze operating performance and leverage. Cash flow as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Cash flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital. Adjusted cash flow Provident uses the term adjusted cash flow to refer to cash flow from operations net of the interest paid on the subordinated convertible debentures. Management reviews adjusted cash flow in setting distributions and historically has paid out close to all of its adjusted cash flow as distributions to unitholders. Provident has maintained a high payout ratio of adjusted cash flow in both 2003 and 2002 as it has funded its annual capital program through participation in its Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan program and minor property dispositions. Adjusted cash flow for 2003 was $128.4 million compared to $129.6 million of distributions while in 2002 adjusted cash flow was $92.1 million and distributions totaled $81.5 million. Distributions were 101 percent of adjusted cash flow in 2003 and 89 percent in 2002. Distributions The following table summarizes distributions paid or declared by the Trust since inception:
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Distribution Amount
Record Date Payment Date (Cdn$) (US$)(1)
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2003
January 21 February 14 $0.20 $0.13
February 20 March 14 0.20 0.13
March 20 April 15 0.20 0.14
April 21 May 15 0.20 0.15
May 20 June 13 0.20 0.15
June 18 July 15 0.20 0.14
July 21 August 15 0.17 0.12
August 20 September 15 0.15 0.11
September 18 October 15 0.15 0.11
October 21 November 14 0.15 0.11
November 19 December 15 0.12 0.09
December 18 January 15, 2004 0.12 0.09
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2003 Cash Distributions paid as declared $2.06 $1.47
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2002 Cash Distributions paid as declared $2.03 $1.29
2001 Cash Distributions paid as declared
- March 2001 - December 2001 $2.54 $1.64
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Inception to December 31, 2003
- Distributions paid as declared $6.63 $4.40
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(1) exchange rate based on the Bank of Canada noon rate on the
payment date.
For Canadian residents the tax treatment of the distributions was: 2003 - 59 percent taxable, 41 percent return of capital; 2002 - 48 percent taxable, 52 percent return of capital; 2001 - 40.7 percent taxable, 59.3 percent return of capital.
Net income
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
(000s except per unit data) 2003 2002 2003 2002
---------------------------------------------------------------------
Net income $ 21,067 $ 7,033 $ 33,394 $ 8,340
Per weighted average unit
- basic(1) $ 0.26 $ 0.12 $ 0.38 $ 0.09
Per weighted average unit
- diluted(2) $ 0.26 $ 0.12 $ 0.38 $ 0.09
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(1) Based on weighted average number of trust units and trust units
that would be issued upon conversion of exchangeable shares. Net
income available for distribution to unitholders in the basic and
diluted per trust unit calculations has been reduced by interest
on the convertible debentures.
(2) Based on weighted average number of trust units and trust units
that would be issued upon conversion of exchangeable shares and
conversion of the convertible debentures.
Comparative figures for net income have been restated due to the retroactive application of the new Asset Retirement Obligation accounting standard. Losses before taxes amounted to $19.8 million for the year and $1.3 million for the quarter, however future tax recoveries of $56.5 million for the year and $23.2 million for the quarter ended December 31, 2003 resulted in the reported income. The OGP business segment contributed $126.7 million of cash flow, $118.0 million of earnings before interest DD&A and taxes, and $25.3 million of net income for the year ended December 31, 2003, ($24.4 million, $25.7 million and $12.9 million for the quarter). The Midstream unit contributed $9.0 million of cash flow, $10.3 million of earnings before interest, taxes and depletion, depreciation and accretion, and $8.1 million of net income for the year ended December 31, 2003.
Taxes
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
2003 2002 2003 2002
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Capital taxes $ 887 $ 1,212 $ 3,332 $ 3,264
Future income taxes recovery $(23,241) $(4,455) $(56,478) $(18,414)
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Comparative figures for future income taxes (recovery) have been restated due to the retroactive application of the new Asset Retirement Obligation accounting standard. The year to date future income tax recovery was primarily caused by changes in Canadian tax legislation. On June 9, 2003 the Canadian government substantially enacted federal income tax changes for the oil and natural gas sector as it had outlined in its 2003 budget. Resource tax rates will decline from the current 27 percent to 21 percent by 2007. Concurrently, the 100 percent deductibility of the resource allowance will be phased out and Crown charges will become 100 percent deductible. These changes, combined with a revision in estimates of Provident's tax pool balances, resulted in the significant future tax recovery in the second quarter and in the year to date recovery. Further tax recoveries were recorded in the fourth quarter as the determination of internal royalty charges moved more projected future taxes into lower tax rate years, resulting in a larger recovery in the quarter. Capital taxes include the Saskatchewan Resource surcharge and federal and provincial large corporation taxes.
Interest expense
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
2003 2002 2003 2002
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Interest on long-term debt $ 2,941 $ 2,196 $ 9,733 $ 5,307
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Interest expense increased for the quarter and year ended December 31, 2003 as compared to the same periods in 2002 due to the increase in the overall size of Provident, with commensurate increases in debt levels. Provident continued to manage debt, and in turn interest expense, prudently in 2003. Capital spending of $32.2 million, excluding the Redwater purchase, was funded through capital dispositions of $9.8 million and proceeds from Provident's Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan (the DRIP) of $27.4 million. The Redwater purchase was financed in part by the $277.0 million bought deal financing that comprised $202.0 million of unit equity and $75.0 million of convertible debentures. Commodity Price Risk Management Program Provident's Commodity Price Risk Management Program involves a disciplined hedging strategy and use of derivative instruments to minimize price risk associated with the volatility of commodity prices. Strategies are selected based on their ability to help Provident provide stable cash flow and distributions per unit rather than to simply lock in a specific price per barrel of oil or cubic foot of natural gas. Provident uses a combination of forward sales contracts, physical hedges on both wellhead prices and heavy oil differentials, financial hedging on WTI crude oil and AECO natural gas prices and Cdn/US exchange rate hedges. For 2003, the Program recorded an opportunity cost of $23.9 million on crude oil ($4.77 per barrel) and an opportunity cost of $25.0 million on natural gas ($0.92 per mcf), compared to an opportunity cost $13.0 million for crude oil ($3.13 per barrel) and a positive impact of $6.6 million for natural gas ($0.32 per mcf) in 2002. The total impact in 2003 was an opportunity cost of $48.9 million ($4.91 per boe) compared to an opportunity cost of $6.4 million ($0.81 per boe) in 2002. In 2003, 46 percent of the opportunity cost or $22.6 million was realized in the first quarter when the WTI crude oil price averaged US$33.80 and natural gas priced at AECO averaged Cdn$7.61 per mcf, quarterly averages that have never before been achieved in tandem at those levels. On a per unit basis the opportunity costs were $0.73 per unit in 2003 and $0.16 per unit in 2002. In the fourth quarter of 2003 the opportunity cost of hedging amounted to $4.9 million compared to $4.0 million of costs in the comparable quarter in 2002. The fourth quarter 2003 Program recorded an opportunity cost of $3.9 million on crude oil ($3.12 per barrel) and an opportunity cost of $1.0 million on natural gas ($0.16 per mcf), compared to an opportunity cost of $2.7 million for crude oil ($2.09 per barrel) and an opportunity cost of $1.3 million for natural gas ($0.15 per mcf) in the comparable quarter in 2002. The estimated mark to market value of open contracts at December 31, 2003 was negative for both crude oil and natural gas, totaling $21.1 million for crude oil and $4.1 million for natural gas based on commodity prices prevailing at December 31, 2003. The contract positions are provided in note 17 to the consolidated financial statements - Financial instruments and hedging.
Liquidity and Capital Resources
December 31,
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2003 2002
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Long-term debt $ 236,500 $ 187,200
Working capital (surplus)/deficit (18,552) 15,681
-----------------------
Net debt 217,948 202,881
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Equity (at book value) 679,228 471,420
-----------------------
-----------------------
Total capitalization at book value $ 897,176 $ 674,301
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Net debt as a percentage of total book
value capitalization 24% 30%
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Bank debt and working capital As at December 31, 2003 Provident had drawn on 80 percent of its $310.0 million revolving term credit facility, comparable to the 74 percent drawn at December 31, 2002. At December 31, 2003 Provident had letters of credit guaranteeing Provident's performance under certain commercial contracts that totaled $12.3 million, marginally increasing bank line utilization to 80 percent. The guarantees are associated with the marketing segment of the midstream business unit. At December 31, 2002 Provident's guarantees were negligible. Provident's net debt (debt net of working capital) and working capital increased by $15.1 million to $217.9 million as at December 31, 2003 compared to $202.9 million as at December 31, 2002. The 2003 year-end working capital surplus of $18.6 million compares to a $15.7 million deficit at 2002 year end with the surplus being primarily attributable to the $24.2 million of inventory associated with the Midstream business unit. Net debt has decreased to 24 percent of total debt and equity, at book values from 30 percent for the prior year. Convertible subordinated debentures In April 2002 the trust issued $64.4 million aggregate principle amount of convertible unsecured subordinated 10.5 percent debentures (10.5 percent debentures) that mature May 15, 2007 with interest payable semi-annually in arrears on May 15 and November 15 each year. The 10.5 percent debentures are convertible at the debenture holder's option into Trust Units at a conversion price of $10.70 per Trust Unit, subject to adjustment in certain circumstances. In 2003, $14.4 million of the debentures were converted into trust units compared to $0.1 million in 2002. Interest recorded on these debentures in 2003 increased to $5.6 million compared to $4.9 million in 2002 reflecting that the debentures were outstanding throughout 2003 compared to under nine months in 2002. On September 30, 2003 the Trust issued $75.0 million aggregate principle amount of convertible unsecured subordinated 8.75 percent debentures (8.75 percent debentures) that mature December 31, 2008 with interest payable semi-annually in arrears on June 30 and December 31 in each year commencing December 31, 2003. The 8.75 percent debentures are convertible at the debenture holder's option into Trust Units at a conversion price of $11.05 per Trust Unit, subject to adjustment in certain circumstances. During the three months the debentures were outstanding there were no conversions to trust units and the interest accrued and paid at December 31, 2003 amounted to $1.6 million. The 8.75% debentures were issued September 30, 2003 in conjunction with the Redwater acquisition. The Trust's debentures net of issue costs are currently classified in Unitholders' Equity as the principal amount of the debentures can be settled with either trust units or cash at the time of maturity. Interest on the Debentures is included in Unitholders' Equity as accumulated interest on convertible debentures. Trust Units Effective with the May 2002 distribution, the Trust initiated a premium distribution, and distribution reinvestment plan ("DRIP"). The DRIP permits eligible unitholders to direct their distributions to the purchase of additional units at 95 percent of the average market price as defined in the plan ("Regular DRIP"). The premium distribution component permits eligible unitholders to elect to receive 102 percent of the cash the unitholder would otherwise have received on the distribution date ("Premium DRIP"). Unitholders who participate in either the Regular DRIP or the Premium DRIP are also eligible to participate in the optional unit purchase plan as defined in the plan. 2.6 million units were issued for proceeds of $27.4 million pursuant to this plan during 2003, compared to 1.8 million units for proceeds of $17.7 million in 2002. On September 30, 2003, concurrent with the purchase of the Redwater assets, the trust issued 16,700,000 units, with an additional 2,505,000 units being issued shortly thereafter as the underwriters exercised an overallotment option for proceeds of $201.7 million. In 2002 the trust issued an aggregate of 25.7 million units for proceeds of $257.2 million as part of the Richland and Meota acquisitions, and a further 3.9 million units (proceeds $39.4 million) were issued to partially finance a major property purchase. During the year ended December 31, 2003 the Trust issued 5.7 million units on conversion of exchangeable shares to units (conversion amount $55.5 million) (2002 - 0.6 million units with a conversion amount of $6.9 million), and 1.3 million units on conversion of convertible debentures (conversion amount $14.4 million) (2002 - 0.012 million units with a conversion amount of $0.13 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 public offering prospectus dated January 22, 2004. Proceeds from the issue were initially used to pay down Provident's bank debt and throughout 2004 will be used to finance the board approved 2004 capital budget of $46.0 million.
Capital expenditures and funding
Three Months Ended Year ended
December 31, December 31,
2003 2002 2003 2002
---------------------------------------------------------------------
Capital Expenditures and Funding
Capital Expenditures
Capital expenditures and
site restoration $ (8,155) $ (7,058) $ (34,120) $ (23,297)
Property acquisitions - (41) - (70,936)
Acquisition of Redwater - - (298,638) -
Corporate acquisitions - (32,009) (364) (35,530)
Property dispositions - 5,651 9,947 11,157
----------------------------------------
Net capital expenditures $ (8,155) $(33,457) $(323,175) $(118,606)
----------------------------------------
----------------------------------------
Funded By
Adjusted cash flow net of
declared distributions $ (1,682) $ 4,517 $ (1,247) $ 10,469
Issue of debentures,
net of cost - - 71,800 61,398
Issue of trust units,
net of cost; excluding DRIP 25,410 17 192,854 38,270
DRIP proceeds 5,829 7,521 27,408 17,744
Reimbursements re leasehold
improvements - - 1,437 -
Change in working capital (45,702) 9,302 (18,377) 1,050
Increase (decrease) in long
term bank debt 24,300 12,100 49,300 (10,325)
----------------------------------------
$ 8,155 $ 33,457 $ 323,175 $ 118,606
---------------------------------------------------------------------
---------------------------------------------------------------------
The acquisition of the Redwater assets was funded by the issue of equity and convertible debentures and bank debt. Bank debt of $100.0 million has been allocated to the midstream assets in the segmented reporting in the financial statements. Capital expenditures were funded by a combination of DRIP proceeds and proceeds received on non-core property dispositions. Provident's strategy is to fund acquisitions by accessing the capital markets and to fund capital expenditures through DRIP and other equity if needed. Net asset value Provident's net asset value ("NAV") at January 1, 2004 is summarized in the table below. The net asset value is calculated on a fully diluted basis, which includes exchangeable shares and unit options, and presented with two discounted cash flow cases with the convertible debentures treated as equity and debt.
At January 1, 2004 Discounted at Discounted at
($000s, except for unit data) 10 percent 8 percent
---------------------------------------------------------------------
Present value of proved plus probable
oil and natural gas reserves (1) $ 418,422 $ 444,392
Midstream assets (2) 345,083 395,864
Undeveloped land (3) 28,016 28,016
Unit Option proceeds 44,340 44,340
Net debt including working capital (217,948) (217,948)
---------------------------------------------------------------------
Net asset value $ 617,913 $ 694,664
---------------------------------------------------------------------
Units Fully Diluted (thousands) 100,315 100,315
---------------------------------------------------------------------
NAV per unit(4) $ 6.16 $ 6.92
---------------------------------------------------------------------
NAV per unit (debentures as debt) $ 5.55 $ 6.41
---------------------------------------------------------------------
(1) Evaluated by McDaniel & Associates Consultants Ltd. effective
January 1, 2004: includes hedging
(2) The midstream assets were acquired on September 30, 2003 for
CDN$283.2 million plus inventory. Discounted cash flows were
determined using annual EBITDA of $38MM for 20 years
(3) Evaluated by Seaton-Jordon & Associates Ltd. effective January 1,
2004
OGP Segment Review
Crude oil price
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
% %
2003 2002 change 2003 2002 change
---------------------------------------------------------------------
Oil per barrel
WTI (US$) $31.18 $28.17 11 $31.02 $26.11 19
Exchange rate
(from US$to Cdn$) $ 1.32 $ 1.56 (15) $ 1.41 $ 1.56 (10)
WTI expressed in
Cdn$ $41.16 $43.95 (6) $43.74 $40.73 7
Corporate realized
crude oil and
natural gas
liquids price
before hedging
(Cdn$) $27.02 $30.08 (10) 30.77 29.62 4
Corporate realized
light/medium oil
price before
hedging (Cdn$) $32.79 $35.65 (8) $36.02 $34.90 3
Corporate realized
heavy oil price
before hedging
(Cdn$) $20.61 $22.73 (9) $24.74 $25.46 (3)
Corporate realized
natural gas
liquids price
before hedging
(Cdn$) $34.48 $33.82 2 $35.87 $29.04 24
---------------------------------------------------------------------
Provident's realized oil and natural gas liquids price, prior to the impact of hedging, decreased by 10 percent to $27.02 per barrel in the fourth quarter of 2003 compared to $30.08 per barrel in the fourth quarter of 2002. The 2003 decrease related to a higher US$ WTI crude oil price offset by a stronger Canadian dollar combined with a greater share of lower priced heavy oil in the fourth quarter 2003 corporate production mix at 48 percent compared to 42 percent in the comparable quarter in 2002. For 2003, the 19 percent increase in WTI did not lead to a commensurate increase in Provident's realized oil and natural gas liquids price, prior to the impact of hedging, as Provident's price was eroded by the stronger Canadian dollar partially offset by a decreased percentage of production of lower priced heavy oil. Heavy oil production as a percentage of total crude oil and natural gas liquids production in 2003 was 46 percent compared to 51 percent in 2002. The decrease in the year over year percentage of heavy oil production was mainly due to the October 1, 2002 Meota Resources Corp. acquisition that added a higher percentage of light oil to Provident's overall liquids production mix in the fourth quarter of 2002 and throughout all of 2003.
Natural gas price
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
% %
2003 2002 change 2003 2002 change
---------------------------------------------------------------------
AECO (Cdn$) $ 5.59 $ 5.60 - $ 6.69 $ 4.05 65
Gas revenue per
mcf (1)(Cdn$) $ 5.62 $ 5.21 8 $ 6.63 $ 4.35 52
(1) Excluding the effects of the commodity price risk management
program
---------------------------------------------------------------------
Provident's realized natural gas price, excluding hedges, increased 8 percent in the fourth quarter of 2003 as compared to the fourth quarter of 2002, prices realized for natural gas averaged 52 percent over 2002, reflecting very strong gas prices throughout the year.
Production
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
% %
2003 2002 change 2003 2002 change
---------------------------------------------------------------------
Daily production
Crude oil
- Light/Medium
(bpd) 6,454 7,478 (14) 6,812 5,096 34
- Heavy (bpd) 7,151 6,459 11 6,902 6,310 9
Natural gas
liquids (bpd) 1,145 1,558 (27) 1,167 1,030 13
Natural gas (mcfd) 68,657 91,766 (25) 74,596 56,193 33
Oil equivalent
(boed) (1) 26,193 30,790 (15) 27,314 21,801 25
(1) Provident reports equivalent production converting natural gas to
oil on a 6:1 basis.
---------------------------------------------------------------------
The 2003 fourth quarter 15 percent decrease in daily production to 26,193 boed compared to 30,790 boed in the fourth quarter of 2002 reflects natural production declines partially offset by drilling and optimization activities conducted primarily in the Lloydminster core area. The 25 percent increase in 2003 production to average 27,314 boed compared to 21,801 boed in 2002 is primarily attributable to production associated with acquisitions closed in 2002 that were incorporated in Provident's production averages for a full year in 2003. Provident's 2003 drilling program coupled with other production optimization activities, added approximately 3,200 boed of initial production primarily from the Lloydminster core area. The 2003 drilling program production additions have offset natural gas and natural gas liquids production declines in West Central Alberta at Brazeau and Gilby. The 2003 daily production mix was 46 percent natural gas, 25 percent conventional heavy oil and 29 percent medium/light crude oil and natural gas liquids. The mix was relatively unchanged from the 2002 production mix of 43 percent natural gas, 29 percent conventional heavy oil and 28 percent medium/light crude oil and natural gas liquids. No single property within Provident's portfolio exceeds 10 percent of daily production. Provident's $46.0 million, 2004 board approved capital budget will focus primarily on shallow gas opportunities in Southern Alberta and Southern Saskatchewan. The production adds forecasted with the anticipated capital spending offset by natural production declines results in estimated average production for 2004 of 24,300 boed.
Revenue and royalties
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
% %
2003 2002 change 2003 2002 change
---------------------------------------------------------------------
Oil
Revenue $ 33,034 $ 38,034 (13) $ 151,874 $ 123,543 23
Cash hedging (3,910) (2,685) (46) (23,892) (13,029) (83)
Royalties
(net of ARTC) (6,475) (6,621) (2) (29,156) (22,469) 30
------------------------------------------------------
Net revenue $ 22,649 $ 28,728 (21) $ 98,826 $ 88,045 12
------------------------------------------------------
------------------------------------------------------
Net revenue
(per barrel) $ 18.09 $ 22.40 (19) $ 19.74 $ 21.15 (7)
Royalties as
a percentage
of revenue 19.6% 17.4% 13 19.2% 18.2% 5
Natural gas
Revenue $ 35,724 $ 43,981 (19) $ 180,590 $ 89,131 103
Cash hedging (925) (1,302) 29 (25,042) 6,550 -
Amortization
of deferred
hedging (84) (1,199) 93 (827) (9,477) 91
Royalties
(net of ARTC) (7,237) (9,613) (25) (39,190) (19,191) 104
------------------------------------------------------
Net revenue $ 27,478 $ 31,867 (14) $ 115,531 $ 67,013 72
------------------------------------------------------
------------------------------------------------------
Net revenue
(per mcf) $ 4.35 $ 3.77 15 $ 4.24 $ 3.27 30
Royalties as
a percentage
of revenue 20.3% 21.9% (7) 21.7% 21.5% 1
Natural gas liquids
Revenue $ 3,630 $ 4,848 (25) $ 15,282 $ 10,915 40
Royalties (888) (903) (2) (4,523) (2,654) 70
------------------------------------------------------
Net revenue $ 2,742 $ 3,945 (30) $ 10,759 $ 8,261 30
------------------------------------------------------
------------------------------------------------------
Net revenue
(per barrel) $ 26.04 $ 27.51 (5) $ 25.25 $ 21.98 15
Royalties as
a percentage
of revenue 24.5% 18.6% 32 29.6% 24.3% 22
Total
Revenue $ 72,388 $ 86,863 (17) $ 347,746 $ 223,589 56
Cash hedging (4,835) (3,987) (21) (48,934) (6,479) (655)
Amortization
of deferred
hedging (84) (1,199) 93 (827) (9,477) 91
Royalties
(net of ARTC) (14,600) (17,137) (15) (72,869) (44,314) 64
------------------------------------------------------
Net revenue $ 52,869 $ 64,540 (18) $ 225,116 $ 163,319 38
------------------------------------------------------
------------------------------------------------------
Net revenue
per boe $ 21.94 $ 22.78 (4) $ 22.58 $ 20.52 10
Royalties as
a percentage
of revenue 20.2% 19.7% 3 21.0% 19.8% 6
---------------------------------------------------------------------
---------------------------------------------------------------------
Quarter over quarter oil, fourth quarter natural gas and natural gas liquids revenue have decreased from 2002 to 2003 due to natural production declines offset by drilling and optimization projects primarily within the Lloydminster core area and reduced net prices after hedging and royalties. Year over year, crude oil, natural gas and natural gas liquids revenue have increased primarily due to acquisitions closed in 2002 that were incorporated in Provident's revenue for the full year in 2003. The royalty burdens for 2003, expressed as a percentage of gross revenues, increased to 21 percent from 20 percent in 2002 due to the fact the percentage royalty paid increases as commodity prices increase and the increase in natural gas as a percentage of Provident's production mix. Natural gas generally bears higher royalty rates than royalties on crude oil. In the future Provident's royalty rates will be dependent on its production mix and movements in commodity prices.
Production expenses
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
% %
2003 2002 change 2003 2002 change
---------------------------------------------------------------------
Production expenses $21,653 $18,468 17 $76,396 $52,741 45
Production expenses
(per boe) $ 8.99 $ 6.52 38 $ 7.66 $ 6.63 16
---------------------------------------------------------------------
Production expenses increased 45 percent to $76.4 million from $52.7 million in 2002. The increase was due to the 48 percent increase in daily average production volumes year over year. On a boe basis in 2003, production expenses increased each quarter reflecting declining production volumes bearing the fixed cost component of operating costs over fewer barrels of oil equivalent production. Further, higher costs for electricity, propane, processing fees and equalization costs and increased servicing and workover costs contributed to the 16 percent increase in per boe operating expenses. The year over year increase in per boe operating costs is consistent with Provident's peers and industry trends. Fourth quarter 2003 operating costs of $21.6 million were 17 percent above the $18.0 million of operating costs incurred in the fourth quarter of 2002 despite 2003 fourth quarter production volumes that were 15 percent below the fourth quarter of 2002. On a boe basis operating costs at $8.99 per boe were 38 percent above the $6.52 per boe incurred in the comparable 2002 quarter. An increase in fourth quarter 2003 production expenses included recording non-operated expenses from prior to September 30, 2003 as well as adjustments to adequately account for expenses that should be recorded and classified in the 2003 year end. Unit operating costs of $6.52 per boe for the fourth quarter of 2002 were affected by flush short term production in the quarter absorbing more fixed costs. Operating costs for 2004 are forecast to average in the range of $7.50 - $8.00 per boe. Oil and Natural Gas Reserves Provident's oil and natural gas reserves as of January 1, 2004 were evaluated or reviewed by McDaniel and Associates (McDaniel). McDaniel evaluated the properties that comprise approximately 75 percent of the value of the company with the properties making up the remaining 25 percent evaluated by qualified Provident staff and ultimately reviewed by McDaniel. In 2002, McDaniel evaluated 100 percent of Provident's properties. No significant properties were added to Provident's portfolio in 2003. The evaluation report used the McDaniel's price forecast at January 1, 2004 and is prepared in accordance with new disclosure standards as mandated by the Canadian Securities Administrators' National Instrument 51-101 (NI-51-101) Standards of Disclosure for Oil and Gas Activities. NI-51-101 establishes prescribed disclosures regarding oil and natural gas information, replacing National Policy 2-B (NP 2-B). NI-51-101 enhances current corporate governance measures by mandating the involvement of independent reserves evaluators in the preparation of reserves data and assigning responsibility for the content of reserves data directly to management and the board of directors. Under NI-51-101, proved reserves are defined as having a high degree of certainty to be recoverable and probable reserves are defined as those reserves that are less certain to be recovered than proved reserves. The targeted levels of certainty, in aggregate, are at least 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves and at least a 50 percent probability that the quantities recovered will equal or exceed the sum of the estimated proved plus probable reserves. The most significant aspect of the transition to reporting under NI-51-101 standards is the definition of proved plus probable as a "best estimate" of future recoverable reserves. It has been generally accepted by the industry that the proved plus probable category under NI 51-101 is comparable to prior years' established reserves. Under NP 2B Provident believed its January 1, 2003 established reserves represented a conservative "best estimate" of the remaining reserves at that time. Under McDaniel's NI-51-101 evaluation Provident had minimal revisions to its reserves on a company interest basis. Before accounting for production, proved plus probable reserves were virtually flat when compared to established reserves on January 1, 2003 as were year over year comparisons of proved developed producing reserves. The proved plus probable category was revised upward by 1.0 percent while the proved developed producing reserve had a slight downward revision of 1.5 percent overall. The total proved category was revised downward by 5.6 percent primarily as a result of competitive drainage at the Brazeau and Gilby natural gas fields. Provident realized a 3.0 percent increase in its proved developed producing reserves as a percent of total proved reserves from 82 percent in 2002 to 85 percent at year end 2003. Production in 2003 totaled 9,970 Mboe and along with , additions and revisions, resulted in a proved plus probable opening balance at January 1, 2004 of 54,894 Mboe compared to 64,501 Mboe on January 1, 2003. The results of McDaniel's evaluation are summarized in the tables below. The following reconciliation summarizes Provident's reserve activity for the year ended December 31, 2003, on both a company working interest and net interest after royalties:
Proved Developed Producing
Light &
Company Share Medium Heavy Total
(WI +RI) (a)(d) Crude Oil Crude Oil Crude Oil
Mbbl Mbbl Mbbl
--------------------------------------------------------------------
Balance at
January 1, 2003 13,991.7 4,899.3 18,891.0
Production (2,486.2) (2,519.2) (5,005.4)
Acquisition 0.0 0.0 0.0
Divestiture (156.8) 0.0 (156.8)
Exploration
Discoveries 0.0 0.0 0.0
Drilling Extensions 77.8 773.1 850.9
Infill Drilling 0.0 0.0 0.0
Improved Recovery 0.0 0.0 0.0
Economic Factors (73.6) (115.8) (189.5)
Technical Revisions (158.1) 900.0 741.9
--------------------------------------------------------------------
Balance at
January 1, 2004 11,194.8 3,937.4 15,132.1
--------------------------------------------------------------------
Net Share (WI) (b)
Balance at
January 1, 2004 9,544.5 3,372.1 12,916.6
--------------------------------------------------------------------
--------------------------------------------------------------------
Company Share
(WI +RI) (a)(d) Gas NGL BOE
MMcf Mbbl Mboe
--------------------------------------------------------------------
Balance at
January 1, 2003 146,042.0 2,175.0 45,406.0
Production (27,227.6) (426.2) (9,969.5)
Acquisition 4.1 0.3 1.0
Divestiture (792.6) (7.1) (296.0)
Exploration
Discoveries 0.0 0.0 0.0
Drilling Extensions 1,022.6 4.1 1,025.4
Infill Drilling 0.0 0.0 0.0
Improved Recovery 0.0 0.0 0.0
Economic Factors 142.2 0.7 (165.1)
Technical Revisions (10,171.6) 416.7 (536.7)
--------------------------------------------------------------------
Balance at
January 1, 2004 109,019.1 2,163.5 35,465.5
--------------------------------------------------------------------
Net Share (WI) (b)
Balance at
January 1, 2004 87,810.1 1,657.5 29,209.2
--------------------------------------------------------------------
--------------------------------------------------------------------
Total Proved
Light &
Company Share Medium Heavy Total
(WI +RI) (a)(d) Crude Oil Crude Oil Crude Oil
Mbbl Mbbl Mbbl
--------------------------------------------------------------------
Balance at
January 1, 2003 15,261.2 9,249.8 24,511.0
Production (2,486.2) (2,519.2) (5,005.4)
Acquisition 0.0 0.0 0.0
Divestiture (201.2) 0.0 (201.2)
Exploration
Discoveries 0.0 0.0 0.0
Drilling Extensions 77.8 773.1 850.9
Infill Drilling 0.0 0.0 0.0
Improved Recovery 0.0 0.0 0.0
Economic Factors (73.2) (138.9) (212.0)
Technical Revisions (806.1) 108.4 (697.8)
--------------------------------------------------------------------
Balance at
January 1, 2004 11,772.3 7,473.2 19,245.5
--------------------------------------------------------------------
Net Share (WI) (b)
Balance at
January 1, 2004 10,280.0 6,557.4 16,585.4
--------------------------------------------------------------------
--------------------------------------------------------------------
Company Share
(WI +RI) (a)(d) Gas NGL BOE
MMcf Mbbl Mboe
--------------------------------------------------------------------
Balance at
January 1, 2003 169,470.0 2,390.0 55,146.0
Production (27,227.6) (426.2) (9,969.5)
Acquisition 4.1 0.3 1.0
Divestiture (6,241.4) (67.1) (1,308.5)
Exploration
Discoveries 0.0 0.0 0.0
Drilling Extensions 1,390.3 4.1 1,086.8
Infill Drilling 0.0 0.0 0.0
Improved Recovery 0.0 0.0 0.0
Economic Factors 134.2 0.7 (188.9)
Technical Revisions (15,436.2) 371.3 (2,899.2)
--------------------------------------------------------------------
Balance at
January 1, 2004 122,093.4 2,273.2 41,867.6
--------------------------------------------------------------------
Net Share (WI) (b)
Balance at
January 1, 2004 98,227.9 1,745.0 34,701.7
--------------------------------------------------------------------
--------------------------------------------------------------------
Total Proved Plus Probable (c)
Light &
Company Share Medium Heavy Total
(WI +RI) (a)(d) Crude Oil Crude Oil Crude Oil
Mbbl Mbbl Mbbl
--------------------------------------------------------------------
Balance at
January 1, 2003 17,488.7 12,252.3 29,741.0
Production (2,486.2) (2,519.2) (5,005.4)
Acquisition 0.0 0.0 0.0
Divestiture (255.3) 0.0 (255.3)
Exploration
Discoveries 0.0 0.0 0.0
Drilling Extensions 96.5 898.9 995.0
Infill Drilling 0.0 0.0 0.0
Improved Recovery 0.0 0.0 0.0
Economic Factors 25.8 (232.7) (206.8)
Technical Revisions 100.8 1,476.6 1,577.4
--------------------------------------------------------------------
Balance at
January 1, 2004 14,970.3 11,875.6 26,845.9
--------------------------------------------------------------------
Net Share (WI) (b)
Balance at
January 1, 2004 12,746.7 10,520.3 23,267.0
--------------------------------------------------------------------
--------------------------------------------------------------------
Company Share
(WI +RI) (a)(d) Gas NGL BOE
MMcf Mbbl Mboe
--------------------------------------------------------------------
Balance at
January 1, 2003 192,129.5 2,738.5 64,501.1
Production (27,227.6) (426.2) (9,969.5)
Acquisition 4.1 0.3 1.0
Divestiture (7,313.9) (76.9) (1,551.2)
Exploration
Discoveries 0.0 0.0 0.0
Drilling Extensions 1,612.7 5.2 1,269.0
Infill Drilling 0.0 0.0 0.0
Improved Recovery 0.0 0.0 0.0
Economic Factors 165.2 8.1 (171.2)
Technical Revisions (7,978.4) 566.7 814.3
--------------------------------------------------------------------
Balance at
January 1, 2004 151,391.6 2,815.7 54,893.5
--------------------------------------------------------------------
Net Share (WI) (b)
Balance at
January 1, 2004 122,164.4 2,166.5 45,794.2
--------------------------------------------------------------------
--------------------------------------------------------------------
(a) Company share includes working interest (WI) and royalty
interests (RI).
(b) Net share includes the Companies working interests only (WI),
and excludes volumes associated with royalties paid to others.
(c) Proved plus Probable reserves at January 1, 2003 represent the
Company's Established reserves from its January 1, 2003 report.
(d) Tables may not add due to rounding.
Provident's oil and natural gas reserves and present value of
estimated future cash flows based on forecast (escalated) price
assumptions are summarized below.
Reserves Summary(b)
Gross Reserves
----------------------------------------------------
Light &
Medium Heavy
Crude Crude Natural
Oil Oil Oil NGLs Gas Boe
----------------------------------------------------
(mbbls) (mbbls) (bcf) (mboe)
Proved Reserves
Producing 11,195 3,937 15,132 2,164 109.0 35,466
Non-Producing 228 507 736 62 10.9 2610
Undeveloped 349 3,028 3,378 48 2.2 3,792
----------------------------------------------------
Total Proved 11,772 7,473 19,246 2,273 122.1 41,868
Probable 3,198 4,402 7,600 543 29.3 13,026
----------------------------------------------------
TOTAL Proved
plus Probable 14,970 11,876 26,846 2,816 151.4 54,894
----------------------------------------------------
----------------------------------------------------
Net Reserves
----------------------------------------------------
Light &
Medium Heavy
Crude Crude Natural
Oil Oil Oil NGLs Gas Boe
----------------------------------------------------
(mbbls) (mbbls) (bcf) (mboe)
Proved Reserves
Producing 9,544 3,372 12,917 1658 87.8 29,209
Non-Producing 187.0 439 626 48 8.6 2,113
Undeveloped 297 2,746 3,043 39 1.8 3,380
----------------------------------------------------
Total Proved 10,028 6,557 16,585 1,745 98.2 34,702
Probable 2,719 3,963 6,682 422 24.0 11,093
----------------------------------------------------
TOTAL Proved
plus Probable 12,747 10,520 23,267 2,167 122.2 45,794
----------------------------------------------------
----------------------------------------------------
The following table summarizes the McDaniel's price forecast used in evaluating Provident's reserves under the escalated pricing assumptions:
Present Value of Reserves(b)
Present Worth Value Discounted at (a)
-------------------------------------------------
0% 8% 10% 15% 20%
-------------------------------------------------
(000's)
Proved Reserves
Producing $439,909 $338,189 $322,335 $289,979 $264,991
Non-Producing 9,601 9,051 8,762 8,028 7,345
Undeveloped 20,002 13,389 12,157 9,582 7,561
-------------------------------------------------
Total Proved 469,511 360,629 343,255 307,589 279,896
Probable 150,372 83,763 75,167 59,301 48,444
-------------------------------------------------
TOTAL Proved
plus Probable $619,883 $444,392 $418,422 $366,890 $328,339
-------------------------------------------------
-------------------------------------------------
(a) Present values include the affects of hedging
(b) Tables may not add due to rounding
Reserves pricing summary
WTI @ Light, Sweet Heavy Oil @ Average Alberta
US$/Cdn$ Cushing @ Edmonton Hardisty Natural Gas
Exchange Oklahoma Cdn$/bbl Cdn$/bbl Price
Rate US$/bbl Cdn$/mmbtu
----------------------------------------------------------------------
2004 0.75 29.00 37.70 22.70 5.65
2005 0.75 26.50 34.30 21.55 5.30
2006 0.75 25.50 33.00 21.56 4.95
2007 0.75 25.00 32.30 20.63 4.75
2008 0.75 25.00 32.30 20.39 4.60
----------------------------------------------------------------------
National Instrument 51-101 Oil and natural gas reserves estimation and reporting has been governed by National Policy 2B (NP 2B) since the late 1970's. As a result of concern expressed by many market participants over the quality and consistency of oil and gas reserves estimates, the Alberta Securities Commission established the Oil and Gas Taskforce in June 1998. The Taskforce, working with the Canadian Institute of Mining, Metallurgy & Petroleum (CIM), and the Calgary chapter of the Society of Petroleum Evaluations Engineers developed recommendations to standardize reserve definitions, as well as the Canadian Oil and Gas Evaluations ("COGE") handbooks to provide guidance for engineers and geologists on recommended reserves booking practices. The Canadian Securities Association proposed new standards that govern all aspects of reserves disclosure in the form of National Instrument 51-101 (NI I 51-101). Reserve definitions The following outlines the main differences between reserves definitions and evaluations practices between NP 2B and NI 51-101. Under both sets of guidelines proved reserves are "those reserves that can be estimated with a high degree of certainty to be recoverable". It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. While similar in this respect to NP 2B, NI 51-101 further identifies the targeted certainty level for proved reserves as "at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proved reserves". Probable reserves are "those additional reserves that are less certain to be recovered than proved reserves. It is likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves". NI 51-101 further defines the targeted certainty level as "at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus probable reserves." As a result the proved plus probable reserves under NI 51-101 represent a "best estimate" of the reserves to be ultimately recovered. Under NP 2B the best estimate of reserves was determined by adding 50 percent of the probable reserves to the proven reserves to allow for the risk associated with these quantities. Historically under NP 2B, companies were not required to report reserves on a net interest basis. NI 51-101 changes this and requires that companies report and reconcile their reserves on a "net interest" basis, or working interest and royalties receivable, less royalties payable. In the interests of continuity both the company interest and net interest tables are provided. The individual components of the reserve reconciliation table are outlined below. Opening Balance: Company or net interest reserves reported in the evaluation being reconciled to. Exploration Discoveries: Additions to reserves where no reserves were previously booked. Drilling Extensions: Additions to reserves resulting from capital expenditures for step-out drilling in previously discovered reservoirs. Infill Drilling: Additions to reserves resulting from capital expenditures for infill drilling in previously discovered reservoirs that were not drilled for enhanced recovery schemes and that were not previously included in the initial reserves assignment. Improved Recovery: Additions to reserves resulting from capital expenditures associated with the installation of enhanced recovery schemes that were not previously included in reserves in that category. Economic Factors: Changes to reserves between the current and previous reporting periods resulting from different price forecasts, inflation rates, and regulatory changes. Technical Revisions: Positive or negative reserves revisions to a reserves entity resulting from new technical data or revised interpretations on previously assigned reserves. Acquisitions and Dispositions: Positive or negative changes to the reserves estimates as a result of purchasing or selling all or a portion of an interest in oil and gas properties. Production: Reserves reductions due to production during the time period being reconciled. Closing Balance: Company or net interest reserves assigned at the end of the period being reconciled. Reserve life index ("RLI") The 2003 year end RLI's were determined by applying the average 2004 production rate from the McDaniel evaluation to the remaining volumes as of January 1, 2004. The proved plus probable RLI's for prior to 2003 are based on established reserves under NP 2B with proved plus probable reserves risked at 50%. The following table illustrates the reserve volume and reserve life index for Provident since its inception as a trust.
Reserve summary and reserve life index(a)(b)
Company share (WI + RI)
December 31,
Total Crude oil 2003 2002 2001
-------------------------------------------------------------------
Proved Producing 3.6 3.7 4.0
Total Proved 4.6 4.9 6.6
Proved plus Probable 6.4 5.9 8.3
Natural gas liquids
-------------------------------------------------------------------
Proved Producing 5.3 4.8 4.6
Total Proved 5.6 5.2 5.3
Proved plus Probable 6.9 6.0 6.3
Natural gas
-------------------------------------------------------------------
Proved Producing 4.9 5.9 4.8
Total Proved 5.5 6.8 5.6
Proved plus Probable 6.8 7.7 6.7
Oil equivalent (6:1)
-------------------------------------------------------------------
Proved Producing 4.3 4.7 4.3
Total Proved 5.0 5.7 6.3
Proved plus Probable 6.6 6.7 7.8
Finding, Development and Acquisition Costs Under NI 51-101, the methodology to be used to calculate finding and development costs ("F&D") implies that F&D and finding, development and acquisition costs ("FD&A costs") include incorporating changes in future development capital ("FDC") required to bring the proved undeveloped and probable reserves to production. As previously noted, this year's "proved plus probable" reserves are compared to prior years "established" reserves which risked the probable reserves at 50 per cent. The table below presents F&D and FD&A costs for both proven and proved plus probable reserves. Costs include all costs of exploring for and developing reserves, including land costs. Acquisition costs include the cash cost of acquiring reserves and the fair value of liabilities assumed. The requirement under generally accepted accounting principles to increase the book value of property plant and equipment and to record an offsetting future tax liability when the purchase price paid on an (usually corporate) acquisition exceeds the available tax pools. This has not been added to FD& A costs. Goodwill was recorded on the acquisitions as part of the purchase price allocation, and therefore forms part of the costs of acquiring the reserves. NI 51-101 does not specifically define reserve additions and does not contemplate nor define acquisition costs. The following table presents reserve additions both including reserve revisions and excluding reserve revisions. If revisions exclude additions, the resultant negative number has been excluded. In 2003, dispositions of oil and gas reserves exceeded additions, and have also been excluded from the table. Provident's FD&A costs since inception including revisions is $12.77 per boe.
Three year
2003 2002 average (2)
---------------------------------------------------------------------
Finding and Development Costs
per boe (includes FDCs)
Proven
Additions $16.20 $14.39 $19.44
Additions including
revisions -(1) -(1) -(1)
Proved plus probable
Additions $17.00 $11.01 $17.92
Additions including
revisions $11.28 -(1) -(1)
Finding, development and
acquisition costs per boe
(includes FDCs)
Proven
Proven excluding
revisions -(1) $13.95 $12.09
Proven including
revisions -(1) $15.20 $15.15
Proved plus probable
Proved plus probable
excluding revisions -(1) $12.42 $11.58
Proved plus probable
including revisions -(1) $13.91 $12.77
---------------------------------------------------------------------
(1) Revisions exceeded additions or dispositions exceeded acquisition,
therefore the calculation is not included in the table.
(2) Three year average is the average from the inception of the Trust
on March 6, 2001.
Other income Other income in 2003 of $1.5 million primarily results from a gain realized on the sale of investments.
General and administrative and management fee expenses
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
Canadian dollars
(000s except % %
per unit data) 2003 2002 change 2003 2002 change
---------------------------------------------------------------------
General and
administrative $4,244 $2,638 61 $14,289 $ 7,987 79
Management fees $ - $7,520 (100) $ - $11,296 (100)
General and
administrative
and management
fees per boe $ 1.76 $ 3.59 (51) $ 1.43 $ 2.42 (41)
---------------------------------------------------------------------
General and administrative and management fee expenses for 2003 were reduced by 26 percent or $5.0 million to $14.3 million from $19.3 million in 2002. On a boe basis the 2003 costs were 39 percent lower at $1.43 per boe compared to $2.42 per boe in 2002. There were no cash management fees incurred in 2003 as the contract was internalized on January 17, 2003. This compared to 2002 management fees of $11.3 million of which $6.3 million was satisfied in cash and $5.0 million was paid in trust units. The fourth quarter 2003 general and administrative and management fees expenses at $4.2 million were 58 percent below the $10.2 million recorded in the fourth quarter of 2002. On a boe basis $1.76 per boe was a 51 percent reduction from last years' levels of $3.59 per boe. For 2004, factoring in anticipated results from the expenditure of the board approved capital budget, general and administrative expenses for OGP are expected to trend in the $1.75 per boe range.
Operating netback
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
% %
2003 2002 change 2003 2002 change
---------------------------------------------------------------------
Netback per boe
Gross
production
revenue $30.04 $30.66 (2) $35.07 $28.10 26
Cash hedging (2.01) (1.41) 43 (4.91) (0.81) 506
-------------------------------------------------
Realized revenue 28.03 29.25 (4) 30.16 27.29 11
Royalties
(net of ARTC) (6.06) (6.05) - (7.31) (5.57) 31
Operating costs (8.99) (6.52) 38 (7.66) (6.63) 16
-------------------------------------------------
$12.98 $16.68 (22) $15.19 $15.09 1
-------------------------------------------------
--------------------------------------------------------------------
The fourth quarter 2003 operating netback of $12.98 per boe was 22 percent lower than $16.68 per boe in the same period in 2002. The reduced netback reflected fourth quarter net realized revenue of $28.03 per boe compared to $29.25 per boe in the 2002 quarter. The lower realized price combined with higher effective royalties as a percentage of the realized price and increased operating costs accounted for the significant decrease compared to the fourth quarter of 2002. The 2003 operating netback of $15.19 per boe was flat to the $15.09 per boe netback in 2002, however, the components of the operating netback differ. Higher gross production revenue was offset by increased opportunity costs associated with the commodity price risk management program, increased royalties as a percentage of the realized price and higher operating costs than in 2002. In 2004 Provident will continue to focus on managing or reducing operating costs to improve operating netbacks.
Depletion, depreciation and accretion (DD&A)
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
Canadian dollars
(000s except
per unit data) 2003 2002 2003 2002
---------------------------------------------------------------------
DD&A $ 31,961 $ 35,606 $ 136,066 $ 90,964
DD&A per boe $ 13.26 $ 12.57 $ 13.65 $ 11.43
---------------------------------------------------------------------
The high DD&A rate is attributable to the method of accounting for corporate acquisitions required under Canadian GAAP. More specifically, the book value of property, plant and equipment is increased by the tax-effected difference between the fair value of assets acquired and tax pools acquired. Over time, the increased DD&A rate is offset by a future tax recovery. The main reason for the year over year increase in DD&A rates was the fourth quarter 2002 Meota acquisition and the tax effected increase in assets acquired being reflected throughout 2003 compared to the fourth quarter of 2002. DD&A includes accretion expense associated with asset retirement obligation of $2.2 million in 2003 (2002 - $1.7 million).
Capital expenditures
Three months ended Year ended
December 31, December 31,
---------------------------------------------------------------------
Canadian dollars
(000s except
per unit data) 2003 2002 2003 2002
---------------------------------------------------------------------
Lloydminster $ 1,469 $ 1,468 $ 12,200 $ 9,670
West central and
southern Alberta 3,298 3,714 11,936 7,497
Southeast and
southwest
Saskatchewan 1,894 1,588 3,854 3,158
Office and other 891 (165) 3,638 1,065
-----------------------------------------------
Total additions $ 7,552 $ 6,605 $ 31,628 $ 21,390
-----------------------------------------------
-----------------------------------------------
Dispositions $ - $ 5,651 $ 9,947 $ 11,157
-----------------------------------------------
---------------------------------------------------------------------
Provident's capital expenditures are primarily funded through the Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan (DRIP). The DRIP program allows investors to reinvest distributions into Trust Units. Provident directs proceeds from the DRIP program ($27.4 million), along with the proceeds from asset dispositions, towards the capital expenditure budget. Provident spent $7.5 million during the fourth quarter of which $1.5 million was spent in the Lloydminster core area drilling four wells and optimizing production through pump upgrades and a fuel gas pipeline installation. Operated and non-operated drilling projects combined with re-completion and facility projects accounted for $3.3 million of spending in west central and southern Alberta. The Company also spent $1.9 million in southeast and southwest Saskatchewan on several re-completion projects, facility work and land purchases. Also, $0.9 million of costs were incurred in the quarter on non-core area capital and office equipment. Provident had a minor adjustment of $0.2 million in the quarter related to dispositions incurred in previous periods. Provident spent $6.6 million in the fourth quarter of 2002 on various drilling, recompleting, optimization and facility projects. Provident incurred capital expenditures of $31.6 million in 2003, of which $12.2 million was spent in the Lloydminster core area drilling and completing 28 net heavy oil wells as well as on land purchases and seismic activity. In Southeast and Southwest Saskatchewan expenditures of $3.9 million were directed at drilling, re-completions, facility projects as well as land purchases for future development. In West Central and Southern Alberta $11.9 million was spent on both operated and non-operated drilling projects as well as on several re-completion, optimization, facility projects and land purchases for future development. Spending on leasehold improvements and office related capital primarily associated with Provident's head office move, as well as capital spending in non-core areas totaled $3.6 million. A total of $1.4 million of a leasehold improvement allowance was received from the landlord in the year and a further portion of the spending on office related capital will result in future rent reductions. In the year Provident disposed of $9.9 million of assets primarily related to the sale of acreage, along with minimal production, to a public Canadian junior oil and gas company. Management considered the risk associated with future development expenditures on the acreage disposed of to be too high for Provident to undertake such development activities. The proceeds on disposition were used to fund a portion of Provident's 2003 capital program. Provident incurred $21.4 million in capital expenditures in 2002 including $12.4 million on drilling projects primarily in the Lloydminster core area, $8.4 million of facility costs and $0.6 million of miscellaneous projects. In addition to the $21.4 million of capital spending, Provident also acquired Southern Alberta properties in 2002 for $72 million. The capital budget approved by the Board of Directors for 2004 for the OGP segment is $46.0 million. Midstream services and marketing On September 30, 2003, Provident acquired Western Canadian midstream assets ("Redwater") for $298.6 million. The purchase price was financed through $35.8 million of long-term debt, $71.8 million of net proceeds from the issuance of convertible debentures, and $191.1 million in net proceeds from the issuance of 19,205,000 trust units.
Provident allocated the purchase price of Redwater as follows:
Net assets acquired:
Petroleum product inventory $ 15,413
Property, plant and equipment
(includes acquisition costs of $6,763) 283,225
---------
$ 298,638
---------
---------
The acquisition was financed by:
Long-term debt $ 35,768
Issuance of trust units (net of costs $10,582) 191,070
Issuance of convertible debentures
(net of costs $3,200) 71,800
---------
$ 298,638
---------
---------
The assets The Midstream business unit processes natural gas liquids (NGL) at the Redwater fractionation, storage and transportation facility located near Edmonton, Alberta. The integrated Redwater system is comprised of three core assets: -- 100 percent ownership of the Redwater NGL Fractionation Facility, a 65,000 barrels per day (bbl/d) fractionation, storage and transportation facility that includes 12 pipeline receipt and delivery points, railcar loading facilities with 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 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. The 2004 board approved capital budget is $1.0 million. Midstream services Provident's midstream services offers customers several types of services and contractual arrangements which include: Fee for service processing - ("Transportation and Fractionation - T&F") In these arrangements, NGL owners (typically natural gas producers) deliver to Provident their NGLs and pay fees for the transportation, processing, fractionation, storage and distribution of their NGL barrels but retain title and are responsible for the marketing of their product. Fixed margin processing: This service involves NGL owners delivering their product to Provident with Provident taking title and paying the NGL owner an amount that is the difference between a delivery price of raw NGLs that is discounted to postings and the posted price in that month for the finished products (this is the "fixed margin") . The discounted price that Provident purchases the product for covers the costs of transportation, processing, fractionation, storage, marketing and distribution of the NGLs. Storage: NGL owners pay fees to store their NGLs. Transport and Distribution: NGL owners pay fees to transport NGLs through the LGS pipeline and use rail and truck loading facilities. The contracts At the Redwater facility, 97 percent of the available capacity is contracted through fee-for-service and fixed margin contracts with major oil and natural gas producers and petrochemical businesses. These contracts account for 93 percent of Midstream Services's total revenue and as a result of these contracts, 67 percent of Redwater's output 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. Plant throughput for the fourth quarter of 2003 averaged 63,616 bpd. Revenues Fourth quarter product sales and services revenues of $143.0 million include T&F processing, fixed margin processing and revenues generated through storage and distribution services and $30.4 million associated with crude oil marketing. 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 $178.0 million for the year relates to NGL product sales revenue included in the product sales and services revenue, where Provident has purchased the natural gas liquids and also includes the cost of crude oil barrels purchased as part of the crude oil marketing business. The NGL costs would be applicable to the fixed margin contracts and a small percentage of volume delivered from the Younger facility on which Provident retains fractionation risk. The majority of the natural gas liquids are purchased pursuant to long-term contracts and annual evergreen purchase commitments. Other expenses The plant has modern technology and low cost operations compared to other existing North American facilities of this type. Operating costs of $7.6 million were representative of normal operations for the quarter without any major turnarounds or operating difficulties. General and administrative expenses of $1.1 million, interest of $1.1 million, and depreciation of $2.2 million for the quarter are estimated by management to also be representative of normal operations for a quarter. Crude oil marketing In July 2003 Provident initiated operations in its crude oil marketing business. During the year $29.1 million revenue was generated from marketing crude oil for third party producers. For the fourth quarter, $16.8 million of revenue was generated marketing third party volumes. Management estimates that marketing of third party volumes, combined with certain Provident crude oil volumes, will provide better producer netbacks than can be achieved through third party marketers. Foreign ownership On September 17, 2003 Canadian unitholders approved an amendment to its 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. Management internalization On January 17, 2003, unitholders of Provident approved a management internalization transaction to eliminate the performance-based arrangement between external management and the Trust for total non-cash consideration of $18.0 million plus $0.6 million of transaction costs. Total non-cash consideration of $18.0 million was settled with the issuance of 1,682,242 exchangeable shares at a deemed price of $10.70 per share that are held in escrow and released 25 percent per year commencing June 2003. The internalization was accretive to cash flow and net asset value and also improves the long-term cost structure of the Trust, which will be beneficial to the Trust's ability to attract capital in a competitive marketplace and complete accretive acquisitions. The transaction also increased ownership of the units held by management and directors further aligning management's interests with those of unitholders. At December 31, 2003 approximately 3.5 percent of the outstanding units and units issuable upon conversion of exchangeable shares were held by management and directors. Business prospects Provident intends to execute a balanced portfolio strategy. In the OGP business internal development projects with a board approved capital budget of $46.0 million are planned. Halo acquisitions of interest in properties close to properties already owned or partially owned by Provident will be pursued. Major corporate or property acquisitions are being evaluated. In the Midstream Services business Provident will expand and build upon the Redwater business and evaluate additional infrastructure assets with a goal of adding quality assets at reasonable prices. The goal of these strategies is to maintain and increase per unit distributable cash flow and net asset value. Sensitivities The following table shows the estimated sensitivity of cash flows to changes in pricing interest, and volume changes taking into account hedge positions currently in place:
Change
(000s) per unit
-----------------------
Pricing
WTI (+US$ 1.00) Oil $ 520 $ 0.0059
AECO (+Cdn$ 0.25) Gas $ 4,212 $ 0.0474
Interest (+1.0%) $ 2,363 $ 0.0266
US exchange (+Cdn$ 0.01) $ 538 $ 0.0061
Volume
Light / Medium Oil (+100 bpd) $ 695 $ 0.0079
Heavy Oil (+100 bpd) $ 462 $ 0.0052
Natural Gas (+1.0 mmcfd) $ 1,362 $ 0.0154
Critical accounting policies Provident's accounting policies are described in note 2 to the consolidated financial statements. Certain accounting policies are identified as critical accounting policies because they form an integral part of Provident's financial position and also require management to make judgments and estimates based on conditions and assumptions that are inherently uncertain. These accounting policies could result in materially different results should the underlying assumptions or conditions change. Management assumptions are based on Provident's historical experience, management's experience, and other factors that, in management's opinion, are relevant and appropriate. Management assumptions may change over time as further experience is gained or as operating conditions change. Details of Provident's critical accounting policies are as follows: Property, plant and equipment Provident follows the full cost method of accounting, whereby all costs associated with the acquisition and development of oil and natural gas reserves are capitalized. Utilization of the full cost method of accounting requires the use of management estimates and assumptions for amounts recorded for depletion and depreciation of property, plant and equipment as well as for the ceiling test. The provision for depletion and depreciation is calculated using the unit of production method based on current production divided by Provident's share of estimated total proved oil and natural gas reserve volumes before royalties. The ceiling test limits the carrying value of oil and natural gas assets, net of future income taxes and asset retirement obligation, to the estimated undiscounted future net production revenue associated with the proved oil and natural gas reserves, plus the unimpaired costs of unproved properties, less estimated future general and administrative expenses, interest and income taxes. Proved reserves are an estimate, under existing reserve evaluation polices, of volumes that can reasonably be expected to be economically recoverable under existing technology and economic conditions. Changes in underlying assumptions or economic conditions could have a material impact on Provident's financial results. To mitigate these risks management utilizes McDaniel & Associates Consultants Ltd., an independent engineering firm, to evaluate Provident's reserves. Estimates of future production, oil and natural gas prices and future costs used in the ceiling test are, by their very nature, subject to uncertainty and changes in underlying assumptions could have a material impact on Provident's financial results. Asset retirement obligation The new Canadian Institute of Chartered Accountants ("CICA") standard for Asset Retirement Obligations changes the method of accounting for certain site restoration costs. Under the new standard, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis, when incurred. The value of the related assets are increased by the same amount as the liability and depreciated over the useful life of the asset. Over time the liability is adjusted for the change in present value of the liability or as a result of changes to either the timing or amount of the original estimate of undiscounted future cash flows. Asset retirement obligation requires that management make estimates and assumptions regarding future liabilities and cash flows involving environmental reclamation and remediation. Such assumptions are inherently uncertain and subject to change over time due to factors such as historical experience, changes in environmental legislation or improved technologies. Changes in underlying assumptions, based on the above noted factors, could have a material impact on Provident's financials results. Changes in accounting policy The following changes in accounting policy were adopted by Provident in 2003. Asset retirement obligation In 2003, the CICA issued Handbook Section 3110, Asset Retirement Obligation (ARO). The new standard requires recognition of the liability associated with future site reclamation costs at the time the liability is incurred. The new standard is effective for fiscal years beginning on or after January 1, 2004, however early adoption is encouraged. Provident early adopted ARO in accordance with the adoption provisions of the standard. The ARO standard requires retroactive application with restatement of comparative periods. Pursuant to the requirement 2002 comparative numbers have been restated to reflect the impact of the new standard. For a review of the impact of ARO on Provident's consolidated financial statements please see Note 3 to the consolidated financial statements, "Changes in accounting policy." Unit based compensation In 2003, Provident adopted CICA Handbook section 3870, "Stock-based compensation and other stock based payments". This change in accounting policy has been applied prospectively. For a review of the impact of section 3870 on Provident's consolidated financial statements please see Note 3 to the consolidated financial statements "changes in accounting policy". Recent accounting pronouncements The following new accounting guidelines or standards are applicable to Provident but have not been implemented. Full cost accounting In 2003, the CICA issued accounting guideline 16, "Oil and Gas Accounting - Full Cost." This accounting guideline replaces accounting guideline 5, "Full cost accounting in the oil and gas industry." The guideline alters the ceiling test calculation and is effective for fiscal years beginning on or after January 1, 2004. Exchangeable shares In 2003, the CICA issued a draft EIC, "Income trusts - exchangeable shares." The EIC proposes that the retained interest of the exchangeable shareholders should be presented on the balance sheet as a non-controlling interest separate and distinct from unitholders' equity. The draft EIC is currently under review and was not enacted in final form as of the time of publication of Provident's consolidated financial statements. Convertible debentures In 2005, in accordance with CICA Handbook section 3860, "Financial instruments - disclosure and presentation," convertible debentures will be required to be classified as a liability on the balance sheet with interest payment recorded as an expense. Provident currently records convertible debentures as unitholders' equity and interest payments on convertible debentures as reductions to unitholders' to equity. Hedging relationships CICA accounting guideline 13, "Hedging relationships" is effective for fiscal periods beginning on or after July 1, 2003. This accounting guideline addresses the identification, designation, documentation and effectiveness of hedging relationships, for the purpose of applying hedge accounting. In addition, it establishes criteria for discontinuing the use of hedge accounting. Under accounting guideline 13, hedging transactions must be documented and it must be demonstrated that the hedges are sufficiently effective to continue accrual accounting for positions hedged with derivatives. Provident does not anticipate applying hedge accounting to its commodity price risk management program. 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 NGL 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 natural 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. Risks Associated With the Level of Foreign Ownership On September 17, 2003, Unitholders approved certain amendments to the Trust Indenture to provide that residency restriction provisions need not be enforced while the Trust is entitled to rely on the provisions of paragraph 132(7)(a) of the Tax Act for the purposes of maintaining its "mutual fund trust" status. The amendments provide that if at any time the board of directors of Provident determines or becomes aware that the Trust's ability to continue to qualify as a "mutual fund trust" based on its asset composition in accordance with paragraph 132(7)(a) of the Tax Act is in jeopardy, then forthwith after such determination (i) the Trust shall not be maintained primarily for the benefit of non-residents of Canada and (ii) Provident shall take such steps as are necessary or desirable to ensure that the Trust is not maintained primarily for the benefit of non-residents of Canada. The retention of "mutual fund trust" status under the Tax Act is important for both resident and non-resident holders of Trust Units and not just for holders of Trust units held within Canadian tax exempt plans. The loss of such status could be expected to have an effect on the market price of the Trust Units. Unit trading activity The following table summarizes the unit trading activity of the Provident units for the year ended December 31, 2003 on both the Toronto Stock Exchange and the American Stock Exchange:
Q1 Q2 Q3 Q4 YTD
--------------------------------------------------------------------
TSX - PVE.UN (Cdn$)
High 11.95 12.75 11.83 11.75 12.75
Low 9.85 10.00 10.45 10.28 9.85
Close 10.29 10.82 10.51 11.43 11.43
Volume (000s) 19,001 25,075 24,068 22,012 90,156
--------------------------------------------------------------------
AMEX - PVX (US$)
High 8.24 9.47 8.53 8.89 9.47
Low 6.60 6.75 7.70 7.81 6.60
Close 7.01 8.06 7.82 8.84 8.84
Volume (000s) 22,625 45,502 30,524 40,261 138,912
--------------------------------------------------------------------
Quarterly table
2003
------------------------------------------------
($000s except per First Second Third Fourth YTD
unit amounts) Quarter Quarter Quarter Quarter Total
Financial -
consolidated
Revenue $ 65,639 $ 56,078 $ 66,375 $ 212,610 $ 400,702
Cash flow $ 41,961 $ 31,571 $ 28,866 $ 33,308 $ 135,706
Net income $ (8,743) $ 23,073 $ (2,003)$ 21,067 $ 33,394
Unitholder
distributions $ 33,091 $ 35,528 $ 28,969 $ 32,023 $ 129,611
Distributions
per unit $ 0.60 $ 0.60 $ 0.47 $ 0.39 $ 2.06
--------------------------------------
Oil and gas
production
Revenue $ 65,639 $ 56,078 $ 54,013 $ 52,781 $ 228,511
Earnings before
interest, DD&A
and taxes $ 26,845 $ 33,989 $ 31,517 $ 25,660 $ 118,011
Cash flow $ 41,961 $ 31,571 $ 28,785 $ 24,385 $ 126,702
Net income $ (8,743) $ 23,073 $ (2,003)$ 12,947 $ 25,274
Midstream
services
and marketing
Revenue $ - $ - $ 23,713 $ 173,435 $ 197,148
Earnings before
interest, DD&A
and taxes $ - $ - $ 81 $ 10,243 $ 10,324
Cash flow $ - $ - $ 81 $ 8,923 $ 9,004
Net income $ - $ - $ 81 $ 8,039 $ 8,120
Operating
Oil and gas
production
Light/medium oil
(bpd) 7,825 6,770 6,748 6,454 6,812
Heavy oil (bpd) 6,245 6,700 7,495 7,151 6,902
Natural gas liquids
(bpd) 1,085 1,162 1,276 1,145 1,167
Natural gas (mcfd) 83,924 72,898 73,090 68,657 74,596
------------------------------------------------
Oil equivalent
(boed) 28,602 26,781 27,701 26,193 27,314
Midstream services
and marketing
Redwater throughput
(bpd) - - - 63,616 N/A
(Cdn $)
Average selling price
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
2002
---------------------------------------------------------------------
($000s except per First Second Third Fourth 2002
unit amounts) Quarter Quarter Quarter Quarter Total
Financial
Revenue $ 24,861 $ 36,800 $ 37,286 $ 64,561 $ 163,508
Cash flow $ 15,324 $ 22,642 $ 22,631 $ 36,299 $ 96,896
Net income -
restated (1) $ 823 $ 763 $ (279)$ 7,033 $ 9,932
Unitholder
distributions $ 14,813 $ 17,794 $ 18,839 $ 30,080 $ 81,526
Distributions
per unit $ 0.46 $ 0.49 $ 0.51 $ 0.57 $ 2.03
------------------------------------------------
Operating
Production
Light/medium oil
(bpd) 3,147 5,025 4,691 7,478 5,096
Heavy oil (bpd) 5,712 6,019 7,032 6,459 6,310
Natural gas liquids
(bpd) 850 800 903 1,558 1,030
Natural gas (mcfd) 36,111 48,648 47,728 91,766 56,193
------------------------------------------------
Oil equivalent
(boed) 15,728 19,952 20,581 30,789 21,801
------------------------------------------------
(Cdn $)
Average selling price
Light/medium oil
per bbl
(before hedges) $ 28.88 $ 35.14 $ 37.41 $ 35.65 $ 34.90
Light/medium oil
per bbl
(including hedges) $ 28.88 $ 34.91 $ 37.07 $ 35.26 $ 34.62
Heavy oil per bbl
(before hedges) $ 21.1 $ 27.9 $ 29.35 $ 22.73 $ 25.46
Heavy oil per bbl
(including hedges) $ 19.84 $ 20.15 $ 21.31 $ 18.66 $ 20.02
Natural gas liquids
per barrel $ 21.17 $ 27.01 $ 29.78 $ 33.82 $ 29.04
Natural gas per mcf
(before hedges) $ 3.52 $ 4.2 $ 3.44 $ 5.21 $ 4.35
Natural gas per mcf
(including hedges) $ 4.35 $ 4.52 $ 4.29 $ 5.06 $ 4.67
(1) Restated for the change in accounting policy for asset retirement
obligations described in note 3 to the consolidated financial
statements.
PROVIDENT ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
As at December 31
Canadian dollars (000s)
2003 2002
--------------------------
(restated
note 3)
Assets
Current assets
Cash $ 45 $ 42
Accounts receivable 118,890 47,463
Petroleum product inventory 24,206 -
Assets held for sale - 1,145
Prepaids 5,632 2,605
--------------------------
148,773 51,255
Cash reserve for future site
reclamation (Note 18) 1,829 1,490
Goodwill (Note 4) 102,443 102,443
Property, plant and equipment (Note 7) 884,891 719,859
--------------------------
$ 1,137,936 $ 875,047
--------------------------
--------------------------
Liabilities
Current liabilities
Accounts payable and accrued
liabilities $ 121,832 $ 54,783
Cash distributions payable 8,389 8,153
Payable to the Manager (Note 14) - 4,000
--------------------------
130,221 66,936
Long-term debt (Note 8) 236,500 187,200
Asset retirement obligation
(Notes 3 and 9) 33,182 32,645
Future income taxes (Note 15) 58,805 116,846
Unitholders' Equity
Unitholders' contributions (Note 10) 803,299 513,835
Exchangeable shares (Note 10) 19,518 57,036
Convertible debentures (Note 11) 119,395 61,279
Contributed surplus (Note 13) 1,305 -
Accumulated loss (4,029) (37,423)
Accumulated cash distributions (Note 6) (248,018) (118,406)
Accumulated interest on
convertible debentures (12,242) (4,901)
--------------------------
679,228 471,420
--------------------------
$ 1,137,936 $ 875,047
--------------------------
--------------------------
Commitments (Note 16)
The accompanying notes form an integral part of these consolidated
financial statements.
PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED LOSS
Canadian dollars (000s except per unit amounts)
For the year ended December 31,
2003 2002
--------------------------
(restated
note 3)
Revenue
Sales $ 473,571 $ 207,823
Royalties (72,869) (44,315)
--------------------------
400,702 163,508
Expenses
Cost of goods sold 153,147 -
Production, operating and maintenance 84,040 52,741
General and administrative (Note 12) 16,670 7,987
Management fees (Notes 12 and 14) - 11,296
Management internalization (Note 14) 18,592 -
Interest on long-term debt 9,733 5,307
Depletion, depreciation and accretion 138,272 92,987
--------------------------
420,454 170,318
Loss before taxes (19,752) (6,810)
Capital taxes 3,332 3,264
Future income tax recovery (Note 15) (56,478) (18,414)
--------------------------
(53,146) (15,150)
Net income for the year 33,394 8,340
Accumulated loss, beginning of year (36,064) (45,996)
Retroactive application of changes
in accounting policies (1,359) 233
Accumulated loss, beginning of
year restated (37,423) (45,763)
--------------------------
Accumulated loss, end of year $ (4,029) $ (37,423)
--------------------------
--------------------------
Net income per unit - basic $ 0.38 $ 0.09
--------------------------
--------------------------
- diluted $ 0.38 $ 0.09
--------------------------
--------------------------
The accompanying notes form an integral part of these consolidated
financial statements.
PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
Canadian dollars (000s)
For the year ended December 31,
2003 2002
--------------------------
(restated
note 3)
Cash provided by operating activities
Net income for the year $ 33,394 $ 8,340
Add non-cash items:
Depletion, depreciation and accretion 138,272 92,987
Amortization of deferred charges 621 8,983
Non-cash general and administrative
(Note 12) 1,305 -
Future income tax recovery (56,478) (18,414)
Management internalization (Note 14) 18,592 -
Management fee paid with trust units
(Note 14) - 5,000
--------------------------
Cash flow from operations 135,706 96,896
Change in non-cash working capital (23,377) (7,090)
--------------------------
112,329 89,806
--------------------------
Cash provided by financing activities
Increase (decrease) in long-term debt 49,300 (10,325)
Declared distributions to unitholders (129,612) (81,526)
Issue of trust units, net of issue costs 220,262 56,014
Issue of debentures, net of costs 71,800 61,398
Interest on convertible debentures (7,341) (4,901)
Change in non-cash financing working
capital 28 3,949
--------------------------
204,437 24,609
--------------------------
Cash used in investing activities
Expenditures on property, plant
and equipment (31,628) (21,980)
Acquisition of Redwater (Note 4) (298,638) -
Acquisition of Provident Management
Corp (Note 14) (364) -
Acquisition of Richland Energy
Corporation (Note 4) - (3,389)
Acquisition of Meota Resources Corp.
(Note 4) - (32,141)
Acquisition of oil and natural
gas properties - (70,936)
Proceeds on disposition of oil and
natural gas properties 9,947 11,157
Reclamation fund contributions (2,492) (1,317)
Reimbursement for leasehold
improvements 1,437 -
Change in non-cash investing
working capital 4,975 4,198
--------------------------
(316,763) (114,408)
--------------------------
Increase in cash 3 7
Cash beginning of year 42 35
--------------------------
Cash end of year $ 45 $ 42
--------------------------
--------------------------
Supplemental disclosure of cash
flow information
Cash interest paid including
debenture interest $ 17,876 $ 4,713
Cash capital taxes paid $ 4,077 $ 3,264
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in Cdn$ 000's, except unit and per unit amounts)
December 31, 2003
1. Structure of the Trust Provident Energy Trust (the "Trust") is an open-end unincorporated investment trust created under the laws of Alberta pursuant to a trust indenture dated January 25, 2001, amended from time to time. The beneficiaries of the Trust are the unitholders. The Trust was established to hold, directly and indirectly, interests in petroleum and natural gas properties and commenced operations March 6, 2001. Cash flow is provided to the Trust from the properties owned and operated by Provident Energy Ltd. and directly and indirectly owned subsidiaries and partnerships of the Trust ("Provident"). Cash flow is paid from Provident to the Trust by way of royalty payments, interest payments and principal repayments. The cash payments received by the Trust are subsequently distributed to the unitholders monthly. 2. Significant accounting policies (a) Basis of presentation These consolidated financial statements include the accounts of the Trust and Provident. (b) Property, plant and equipment The Trust follows the full cost method of accounting for oil and natural gas exploration and development activities, whereby all costs associated with the acquisition and development of oil and natural gas reserves are capitalized. Such costs include lease acquisition, lease rentals on non-producing properties, geological and geophysical activities, drilling of productive and non-productive wells, and tangible well equipment. Gains or losses on the disposition of oil and gas properties are not recognized unless the resulting change to the depletion and depreciation rate is 20 percent or more. General and administrative costs are not capitalized other than to the extent that they are directly related to a successful acquisition. All other property, plant and equipment, including midstream assets, are recorded at cost. Inventories used to fill in cavern bottoms are presented as part of property, plant and equipment and stated at historical cost. These inventories are not depreciated. Depletion, depreciation and accretion The provision for depletion and depreciation for oil and natural gas assets is calculated using the unit-of-production method based on current production divided by the Trust's share of estimated total proved oil and natural gas reserve volumes, before royalties. Production and reserves of natural gas and associated liquids are converted at the energy equivalent ratio of six thousand cubic feet of natural gas to one barrel of oil. In determining its depletion base, the Trust includes estimated future costs for developing proved reserves, and excludes estimated salvage values of tangible equipment and the unimpaired cost of unproved properties. Midstream facilities, including natural gas storage facilities and natural gas liquids extraction facilities are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets which are predominantly 30 years. Capital assets related to pipelines are carried at cost and depreciated using the straight-line method over their economic lives. Ceiling test The ceiling test limits the carrying value of oil and natural gas properties, net of future income taxes and asset retirement obligation, to the estimated undiscounted future net production revenue associated with the proved oil and natural gas reserves, plus the unimpaired costs of unproved properties, less estimated future general and administrative expenses, interest and income taxes. The test uses costs and prices in effect at the balance sheet date. In the application of the ceiling test, any excess carrying value of the assets on the balance sheet is charged to income in the current period. (c) Inventory Inventories of products are valued at the lower of average cost and net realizable value. (d) Goodwill Goodwill, which represents the excess of purchase price over fair value of net assets received, is assessed at least annually for impairment. To assess impairment, the fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit's assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit's goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impaired amount. Goodwill is not amortized. (e) Asset retirement obligation Provident follows the new Canadian Institute of Chartered Accountants standard for Asset Retirement Obligation ("ARO"). Under this standard the fair value of a liability for an ARO is recorded in the period where a reasonable estimate of the fair value can be determined. When the liability is recorded, the carrying amount of the related asset is increased by the same amount of the liability. The asset recorded is depleted over the useful life of the asset. Additions to asset retirement obligations due to the passage of time are recorded as accretion expense. Actual expenditures incurred are charged against the obligation. (f) Unit option plan Under Provident's Trust Option Plan the exercise price of the option may be reduced in future periods, based upon the cash distributions made on the trust units, at the discretion of the option holder. Therefore, it is not possible to determine a fair value for options granted using a traditional option pricing model. Provident accounts for the unit option plan using the intrinsic value of the option, for unexercised options at the financial statement date. Compensation expense associated with the options is deferred and recognized in earnings over the vesting period of the options with a corresponding increase in contributed surplus. Any changes in the intrinsic value of unexercised options are recognized in earnings in the period of change with a corresponding increase or decrease to contributed surplus. Recoveries of compensation expense will only be recognized to the extent of previously recorded cumulative compensation expense associated with exercised and outstanding options as of the date of the financial statements. Consideration upon exercise of the options, along with the amount recorded as contributed surplus, is recorded as an increase in unitholders' contributions. (g) Financial instruments Provident uses financial instruments and physical delivery commodity contracts from time to time to reduce its exposure to fluctuations in commodity prices, foreign exchange rates and interest rates. Gains and losses relating to these transactions are deferred and recognized in the financial statement category to which the hedge relates at the time the underlying commodity is sold or when the positions are settled. (h) Future income taxes Provident follows the liability method for calculating income taxes. Differences between the amounts reported in the financial statements of the corporate subsidiaries and their respective tax bases are applied to tax rates in effect to calculate the future tax liability. The effect of any change in income tax rates is recognized in the current period income. The Trust is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to the unitholders. As the Trust distributes all of its taxable income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for income taxes has been made in the Trust. (i) Revenue recognition Revenues associated with the sales of Provident's natural gas, natural gas liquids ("NGL's") and crude oil owned by Provident are recognized when title passes from Provident to its customer. Marketing revenues and purchased product are recorded on a gross basis as Provident takes title to product and has the risks and rewards of ownership. Revenues associated with the services provided where Provident acts as agent are recorded as the services are provided. Revenues associated with the sale of natural gas storage services are recognized when the services are provided. (j) Use of estimates The preparation of financial statements requires management to make estimates based on currently available information. In particular, estimates are made by management for amounts recorded for depletion and depreciation of the property, plant and equipment, and asset retirement obligation. The ceiling test uses factors such as estimated proved reserves, production rates, petroleum and natural gas prices and future costs. Due to the inherent limitations in metering and the physical properties of storage caverns the determination of precise volumes of natural gas liquids held in inventory at such locations is subject to estimation. Actual inventories of natural gas liquids can only be determined by draining of the caverns. By their very nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of future periods could be material. 3. Changes in accounting policy Asset retirement obligation The Trust adopted CICA Handbook Section 3110 "Asset Retirement Obligations" effective December 2003. This change in accounting policy has been applied retroactively with restatement of prior periods presented for comparative purposes. Previously, the Trust recognized a provision for future site reclamation based on the unit-of-production method applied to estimated future site abandonment and reclamation costs. As a result of this change, net income for the year ended December 31, 2003 increased by $0.04 million ($0.06 million net of future income tax expense of $0.02 million). At December 31, 2003 the ARO balance increased by $0.5 million to $33.2 million, the net PP&E balance decreased by $4.3 million to $884.9 million and the future tax liability increased by $0.02 million to $58.8 million. The amounts previously reported for 2002 have been restated due to the retroactive application of the new ARO standard. As a result of this change, net income for the year ended December 31, 2002 decreased by $1.6 million ($2.5 million net of future income tax recovery of $0.9 million). At December 31, 2002 the ARO balance increased by $19.9 million to $32.6 million, the net PP&E balance increased by $19.9 million to $719.9 million and the future tax liability increased by $0.9 million to $116.8 million. Opening 2003 accumulated loss increased by $1.4 million ($2.1 million net of future income tax recovery of $0.7) while the opening 2002 accumulated loss decreased by $0.2 million ($0.4 million net of future income tax expense of $0.2 million) to reflect the cumulative impact of additional depreciation, depletion and accretion expense net of the previously recorded provision for site restoration. Unit Option Plan The Trust adopted CICA Handbook Section 3870 "Stock-based compensation and other stock-based payments" effective December 2003. This change in accounting policy has been applied prospectively. As a result of this change, net income for the year ended December 31, 2003 decreased by $1.3 million. At December 31, 2003 contributed surplus increased to $1.3 million due to the implementation of the accounting policy. 4. Acquisitions (a) On September 30, 2003, Provident acquired Western Canadian midstream assets ("Redwater") for $298.6 million. The purchase price was financed through $35.8 million of long-term debt, $71.8 million of net proceeds from the issuance of convertible debentures, and $191.1 million in net proceeds from the issuance of 19,205,000 trust units.
Provident allocated the purchase price of Redwater as follows:
Net assets acquired
Petroleum product inventory $ 15,413
Property, plant and equipment
(includes acquisition costs of $6,763) 283,225
----------
$ 298,638
----------
The acquisition was financed by:
Long-term debt (Note 8) $ 35,768
Issuance of trust units (net of costs $10,582)
(Note 10) 191,070
Issuance of convertible debentures
(net of costs of $3,200) 71,800
----------
$ 298,638
----------
----------
(b) Meota Resources Corp. ("Meota") Effective October 1, 2002 Provident acquired Meota for cash consideration of $27.1 million and 14,517,184 trust units with an ascribed value of $158.3 million, plus 5,858,136 exchangeable shares with an ascribed value of $63.9 million. 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 $ 313,305
Goodwill 89,137
Working capital deficiency, net of cash (2,816)
Long-term debt (86,500)
Site reclamation liability (1,084)
Future income taxes (57,653)
----------
$ 254,389
----------
----------
Consideration
Cash $ 27,134
Acquisition costs incurred 5,007
----------
Total cash consideration 32,141
Trust units issued 158,336
Exchangeable shares issued 63,912
----------
$ 254,389
----------
----------
(c) Richland Petroleum Corporation ("Richland") Effective January 16, 2002 Provident acquired Richland for consideration of 11,157,225 Trust units with an ascribed value of $98.9 million. 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
Cash reserved for future site reclamation $ 372
Goodwill 13,306
Fair market value of financial hedges and
physical contracts for petroleum products 10,133
Property, plant and equipment 219,151
Working capital deficiency (10,744)
Long-term debt (75,425)
Site reclamation liability (1,559)
Future income taxes (52,660)
----------
$ 102,574
----------
----------
Consideration
Acquisition costs incurred
(includes $332 incurred in 2001) $ 3,721
Trust units issued 98,853
----------
$ 102,574
----------
----------
5. Segmented information
Oil and Midstream
Natural Services Inter-
Gas and segment
Production Marketing Elimination Total
Revenue
Gross production
revenue $ 299,904 $ - $ - $ 299,904
Royalties (72,869) - - (72,869)
Product sales and
services revenue - 197,148 (24,957) 172,191
Other revenue 1,476 - - 1,476
------------------------------------------------
228,511 197,148 (24,957) 400,702
Expenses
Cost of goods sold - 178,104 (24,957) 153,147
Production,
operating and
maintenance 76,396 7,644 - 84,040
Cash general and
administrative 14,289 1,076 - 15,365
Non-cash general and
administrative 1,223 82 - 1,305
Management
internalization 18,592 - - 18,592
------------------------------------------------
110,500 186,906 (24,957) 272,449
Earnings before
interest, taxes,
depletion,
depreciation
and accretion 118,011 10,242 - 128,253
Interest on
long-term debt 8,568 1,165 9,733
Depletion,
depreciation
and accretion 136,066 2,206 - 138,272
Capital taxes 3,177 155 - 3,332
Future income tax
recovery (Note 15) (55,074) (1,404) - (56,478)
------------------------------------------------
92,737 2,122 - 94,859
Net income for
the year $ 25,274 $ 8,120 $ - $ 33,394
Capital expenditures
Acquisition of
Redwater $ - $ 298,638 $ - $ 298,638
Property, plant
and equipment 31,628 - - 31,628
Selected balance
sheet items
Working capital
Accounts receivable 47,691 76,106 (4,907) 118,890
Petroleum product
inventory - 24,206 - 24,206
Accounts payable 52,146 74,593 (4,907) 121,832
Long-term debt 136,500 100,000 - 236,500
Provident's business activities are conducted through two business segments; oil and natural gas production and midstream services and marketing. Oil and natural gas production 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. In 2002 Provident operated in only one business segment, oil and natural gas production. Therefore, no segmented comparatives have been presented.
6. Reconciliation of cash flow and distributions
For the year ended December 31,
2003 2002
------------------------------
Cash flow from operations $ 135,706 $ 96,896
Cash reserved for interest on
convertible debentures (7,341) (4,901)
Cash (reserved) used for financing
and investing activities 1,247 (10,469)
------------------------------
Cash distributions to unitholders 129,612 81,526
Accumulated cash distributions,
beginning of year 118,406 36,880
------------------------------
Accumulated cash distributions,
end of year $ 248,018 $ 118,406
------------------------------
7. Property, plant and equipment
Accumulated
depletion Net book
December 31, 2003 Cost and depreciation value
--------------------------------------------------------------------
Oil and natural
gas properties $ 992,804 $ 391,922 $ 600,882
Midstream assets 280,989 2,206 278,783
Office equipment 8,359 3,133 5,226
--------------------------------------------------
Total $ 1,282,152 $ 397,261 $ 884,891
--------------------------------------------------
--------------------------------------------------
Accumulated
December 31, 2002 depletion Net book
(restated - note 3) Cost and depreciation value
--------------------------------------------------------------------
Oil and natural
gas properties $ 973,598 $ 255,901 $ 717,697
Office equipment 4,042 1,880 2,162
--------------------------------------------------
Total $ 977,640 $ 257,781 $ 719,859
--------------------------------------------------
--------------------------------------------------
Costs associated with unproved properties excluded from costs subject to depletion as at December 31, 2003 totaled $16.4 million (December 31, 2002 - $30.2 million).
8. Long-term debt
December 31,
2003 2002
---------------------
Revolving term credit facility $236,500 $187,200
---------------------
---------------------
Provident has a $335 million term credit facility with a syndicate of Canadian chartered banks. Interest rates under the terms of the credit facility are determined quarterly based on the ratio of quarter end debt divided by the previous quarter's cash flow annualized. At December 31, 2003, the rate was bank prime of 4.5 percent plus 0.5 percent. In February 2004 Provident executed a credit agreement consent and amendment that restricted the borrowing base under this facility to $310 million. Pursuant to the terms of the agreement, each year on or after May 24 Provident can request the revolving period be extended for a further 364 day period. If the lenders do not extend the revolving period, at Provident's option the credit facility is converted to a one year non-revolving term credit facility at the end of the 364 day term, with one-sixth of the loan balance due May 2005, one-twelfth due August 2005 and the remaining balance due at the end of the term period. As collateral security, Provident has pledged a $500 million fixed and floating charge debenture against all of its assets. At December 31, 2003 Provident had letters of credit guaranteeing Provident's performance under certain commercial contracts that totaled $12.3 million, marginally increasing bank line utilization to 80 percent of the restricted borrowing base. The guarantees are associated with the marketing segment of the midstream business unit. At December 31, 2002 Provident's guarantees were negligible. 9. Asset retirement obligation Provident's asset retirement obligation is based on the Trust's net ownership in wells and facilities and management's estimate of the costs to abandon and reclaim those wells and facilities as well as an estimate of the future timing of the costs to be incurred. Midstream assets, including the Redwater facility, the Younger Plant and the liquids gathering system have been excluded from the asset retirement obligation as retirement obligations associated with these assets have indeterminate settlement dates. The total undiscounted amount of future cash flows required to settle asset retirement obligations is estimated to be $99.7 million. Provident has estimated the present value of the asset retirement obligation to be $33.2 million as at December 31, 2003. Payments to settle asset retirement obligations occur over the operating lives of the assets estimated to be from zero to 20 years. Estimated cash flows have been discounted at Provident's credit-adjusted risk free rate of 7 percent and an inflation rate of 2 percent.
For the year ended December 31,
2003 2002
(restated
note 3)
------------------------------
Carrying amount, beginning of year $ 32,645 $ 12,740
Increase in liabilities during
the year 519 18,775
Settlement of liabilities during
the year (Note 18) (2,153) (600)
Accretion expense 2,171 1,730
------------------------------
Carrying amount, end of year $ 33,182 $ 32,645
------------------------------
------------------------------
10. Unitholders' contributions and exchangeable shares The Trust has authorized capital of an unlimited number of common voting trust units. During 2003 the Trust issued 19,205,000 units (16,700,000 on September 30, 2003 and 2,505,000 on exercise of underwriters options) for gross proceeds of $201.7 million, in a financing concurrent with the purchase of the Redwater assets (Note 4). On January 17, 2003 Provident Energy Ltd., a subsidiary, issued 1.7 million exchangeable shares as consideration for the acquisition of Provident Management Corp. (see Note 14). The conversion ratio for the exchangeable shares for the period January 17 to February 14, 2003 was equal to one trust unit for one exchangeable share, and is increased on each date a distribution is paid by the trust. The exchangeable shares are held in escrow and are releasable as to 25 percent per year beginning on June 30, 2003, and are releasable or may be forfeited in certain other limited circumstances. On January 16, 2002, the Trust issued 11.2 million trust units as consideration for the Richland acquisition. On October 1, 2002, the Trust issued 14.5 million trust units and Provident Acquisitions Inc., a subsidiary, issued 5.9 million exchangeable shares as partial consideration for the acquisition of Meota Resources Corp. The conversion ratio for the exchangeable shares for the period October 1 to November 14, 2002 was equal to one trust unit for one exchangeable share, and is increased on each date a distribution is paid by the Trust between October 1, 2002 and the date the exchangeable share is converted, at the option of the holder, into trust units. On January 15, 2005, all remaining exchangeable shares will be automatically exchanged for trust units, subject to extension at the option of the Trust. Effective with the May, 2002 distribution, the Trust initiated a premium distribution, distribution reinvestment plan ("DRIP"). The DRIP permits eligible unitholders to direct their distributions to the purchase of additional units at 95 percent of the average market price as defined in the plan ("Regular DRIP"). The premium distribution component permits eligible unitholders to elect to receive 102 percent of the cash the unitholder would otherwise have received on the distribution date ("Premium DRIP"). Participation in the Regular and Premium DRIP is subject to proration by the Trust. Unitholders who participate in either the Regular DRIP or the Premium DRIP are also eligible to participate in the optional unit purchase plan as defined in the DRIP.
Year ended December 31,
2003 2002
-----------------------------------------
Trust Units Number Amount Number Amount
of Units (000s) of Units (000s)
--------------------------------------------------------------------
Balance at beginning
of year 53,729,335 $ 513,835 21,054,119 $ 187,587
Issued for cash 19,205,000 201,653 - -
Exchangeable share
conversions 5,726,525 55,518 644,150 6,876
Issued pursuant to unit
option plan 202,446 1,626 126,034 1,103
Issued pursuant to the
distribution
reinvestment plan 2,478,956 25,880 1,751,652 17,744
To be issued pursuant
to the distribution
reinvestment plan 141,361 1,528
Debenture conversions 1,341,065 14,350 11,681 125
Issued from Treasury - - 3,900,000 39,390
Issued for corporate
acquisitions - - 25,674,409 257,189
Issued for property
acquisition - - 100,000 1,050
Issued to Provident
Management Corporation - - 467,290 5,000
Unit issue costs - (11,091) - (2,229)
-----------------------------------------
Balance at end of year 82,824,688 $ 803,299 53,729,335 $ 513,835
-------------------------------------------
-------------------------------------------
Year ended December 31,
2003 2002
------------------------------------------
Exchangeable shares Number of Amount Number of Amount
Shares (000s) Shares (000s)
Provident Acquisitions
Inc.
--------------------------------------------------------------------
Balance at beginning
of year 5,227,844 $ 57,036 - $ -
Issued to acquire
Meota Resources Corp. - - 5,858,136 63,912
Converted to trust
units (4,693,487) (51,207) (630,292) (6,876)
------------------------------------------
Balance, end of year 534,357 5,829 5,227,844 57,036
------------------------------------------
Exchange ratio, end of
year 1.2517 - 1.03597 -
Trust units issuable
upon conversion,
end of year 668,855 5,829 5,415,890 $ 57,036
------------------------------------------
------------------------------------------
Exchangeable shares
Number of Amount
Provident Energy Ltd. Shares (000s)
-----------------------------------------------
Balance, December 31,
2002 - $ -
Issued to acquire
Provident Management
Corp. 1,682,242 18,000
Converted to trust
units (403,015) (4,311)
---------------------
Balance, end of year 1,279,227 13,689
Exchange ratio, end of
year 1.18663 -
---------------------
Trust units issuable
upon conversion, end of
year 1,517,969 $ 13,689
---------------------
The per trust unit amounts for 2003 were calculated based on the weighted average number of units outstanding of 68,448,203, which includes the shares exchangeable into trust units. The per trust unit amounts for 2002 were calculated based on the weighted average number of units outstanding of 40,221,914. Net income available for distribution to unitholders in the basic per trust unit calculations has been reduced by interest on the convertible debentures. The diluted per trust unit amounts are calculated including an additional 50,098 trust units (2002 - 56,510) for the dilutive effect of the unit option plan. Provident's convertible debentures are not included in the computation of diluted earning per unit as their effect is anti-dilutive. 11. Convertible debentures On September 30, 2003 the Trust issued $75 million of unsecured subordinated convertible debentures ($71.8 million net of issues costs) with a 8.75 percent coupon rate maturing December 31, 2008. The debentures may be converted into trust units at the option of the holder at a conversion prices of $11.05 per trust unit prior to December 31, 2008, and may be redeemed by the Trust under certain circumstances. 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. 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 debentures and related interest obligations have been classified as equity on the consolidated balance sheet as the Trust may elect to satisfy interest and principle obligations by the issuance of trust units. During the year $14.35 million of 10.5 percent debentures were converted to trust units.
12. General and administrative expenses
Year ended December 31,
2003 2002
-------------------------
General & administrative expenses $ 15,365 $ 7,987
Non-cash general and administrative
expenses (1) 1,305 -
Management fee - 11,296
-------------------------
Total cash, non-cash general and
administrative expenses and management fee $ 16,670 $ 19,283
-------------------------
-------------------------
(1) non-cash general and administrative expenses is made up entirely
by the trust unit incentive compensation expense.
13. Unit option plan
Year ended December 31,
----------------------------------------
2003 2002
----------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
----------------------------------------
Outstanding,
beginning of year 796,810 $10.86 611,100 $11.16
Granted 3,443,550 11.09 345,013 10.32
Exercised (202,446) 10.62 (126,034) 10.87
Cancelled (29,170) 11.18 (33,269) 10.72
----------------------------------------
Outstanding, end of year 4,008,744 11.06 796,810 10.86
----------------------------------------
Exercisable at end of year 1,535,004 $11.07 330,149 $11.09
----------------------------------------
----------------------------------------
The Trust Option Plan (the "Plan") is administered by the Board of Directors of Provident. Under the Plan, all directors, officers, employees and certain consultants of Provident are eligible to participate in the Plan. There are 5,000,000 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 in the following manner; one-third vest six months after the grant date, one-third vest 1.5 years after the grant date and one-third vest 2.5 years after the grant date. At December 31, 2003, the Trust had 4,008,744 options outstanding with exercise prices ranging between $8.40 and $12.39 per unit. The weighted average remaining contractual life of the options is 3.09 years and the weighted average exercise price is $11.07 per unit excluding average potential reductions to the strike prices of $1.26 per unit. At December 31, 2002, the Trust had 796,810 options outstanding with prices ranging from $8.40 and $12.39 per unit. The weighted average exercise price was $11.09 per unit. The weighted average remaining contractual life of the options was 2.8 years. Provident recorded compensation expense and contributed surplus, based on the year end unit price, of $1.3 million for the 3.4 million options granted on or after January 1, 2003. Provident has elected to apply the provision of CICA section 3870 prospectively, therefore, no compensation expense is associated with options granted prior to January 1, 2003. 14. Related party transactions Until January 17, 2003 the Trust was actively managed by Provident Management Corporation (the "Manager"), and in accordance with the terms of the management agreement, the Manager was entitled to receive a base fee in the amount of 2 percent of the operating cash flow of Provident, plus a total return fee based on distributions and unit price performance during the period. Pursuant to the management fee amending agreement approved in conjunction with the management internalization transaction (note 16), the base fee paid for the period January 1 to October 31, 2002 was $1.8 million and $0.5 million for the period November 1 to December 31, 2002, for a total base fee of $2.3 million. The total return fee for 2002 was restricted to $9.0 million, payable by way of $4.0 million in cash and 467,290 trust units valued at $5.0 million. The Manager was reimbursed for administration expenses which totaled $264,242 in 2002. On January 17, 2003, Provident acquired all the issued and outstanding shares of Provident Management Corporation, Manager of the Trust and Provident, for consideration of $18.0 million payable with the issuance of 1,682,242 exchangeable shares. The exchangeable shares are held in escrow and are releasable as to 25 percent per year beginning on June 30, 2003, and are releasable or may be forfeited in certain other limited circumstances. This management internalization transaction eliminates external management fees effective January 1, 2003. The share purchase agreement as a condition of closing provides for executive employment contracts for the former shareholders of Provident Management Corporation. The full cost of this transaction, $18.6 million including transaction costs of $0.6 million, was expensed in 2003. 15. Future income taxes The difference between the accounting value and the income tax value of assets and liabilities, which comprise the future tax liability, are as follows:
December 31,
-------------------------
2003 2002
(restated)
-------------------------
Petroleum and natural gas
properties and other $ 49,273 $ 102,122
Production facilities 8,128 14,724
Midstream facilities 1,404 -
-------------------------
$ 58,805 $ 116,846
The future income tax provision differs from the expected amount calculated by applying the Canadian combined federal and provincial income tax rate of 40.6 percent (2002 - 42.1 percent) as follows:
Year ended December 31,
-----------------------
2003 2002
(restated)
-----------------------
Expected income tax recovery $ (8,019) $ (2,860)
Increase (decrease) resulting from:
Non-deductible Crown charges and
other payments 14,226 12,728
Federal resource allowance (8,563) (7,382)
Alberta Royalty Tax Credit (183) (260)
Payments to the Trust (33,454) (16,808)
Income less related depletion and
depreciation in a wholly owned
partnership and in the Trust 382 (2,630)
Federal income tax rate changes and other (20,867) (1,202)
-----------------------
$ (56,478) $ (18,414)
-----------------------
-----------------------
16. Commitments Under the terms of the Redwater purchase and sale agreement Provident is committed to assumption or cancellation of financial assurances that the vendor had with suppliers. These financial assurances, which guarantee performance under certain commercial contracts, total $14.0 million. Provident has office lease commitments that extend through April 2013. Future minimum lease payments for the following five years are: 2004 - $2.3 million; 2005 - $2.3 million; 2006 - $2.4 million, 2007 - $2.5 million; and 2008 - $2.5 million. 17. Financial instruments and hedging Provident's commodity price risk management program is intended to minimize the volatility of Provident's commodity prices and to assist with stabilizing cash flow and distributions. Provident seeks to accomplish this through the use of financial instruments and physical delivery commodity contracts from time to time to reduce its exposure to fluctuations in commodity prices and foreign exchange rates. Gains and losses relating to these transactions are deferred and recognized in the financial statement category to which the hedge relates at the time the underlying commodity is sold or when the positions are settled. The carrying amounts of current assets, the reclamation fund, current liabilities and long-term debt as stated in the financial statements approximate their estimated fair value. Substantially all of the Trust's accounts receivable are with oil and gas marketers and joint venture partners in the oil and natural gas industry and are subject to normal industry credit risks. With respect to financial instruments, Provident could be exposed to losses if a counter party fails to perform in accordance with the terms of the contract. This risk is managed by diversifying the derivative portfolio among counter parties meeting certain financial criteria. (a) Commodity price (i) Crude oil For 2003, Provident paid out $23.9 million to settle various oil market based contracts on an aggregate volume of 1,867,500 barrels. For 2002, Provident paid out $13.0 million to settle various oil market based contracts on an aggregate volume of 2,286,250 barrels. The estimated value of contracts in place if settled at market prices at December 31, 2003 would have resulted in an opportunity cost of $21.1 million (December 31, 2002 -$13.3 million). The contracts in place at December 31, 2003 are summarized in the following table:
Year Product Volume Terms Effective Period
---------------------------------------------------------------------
2004 Light Oil 4,500 Bpd WTI US$23.41 per bbl January 1 -
December 31
---------------------------------------------------------------------
500 Bpd WTI US$25.08 per bbl January 1 -
March 31
---------------------------------------------------------------------
2005 Light Oil 2,000 Bpd WTI US$25.01 per bbl January 1 -
December 31
---------------------------------------------------------------------
2004 Heavy Oil(1) 2,800 Bpd US$17.96 per bbl January 1 -
at Hardisty December 31
---------------------------------------------------------------------
(1) The heavy oil price of US$17.96 per bbl has been fixed through a
combination of US dollar denominated WTI contracts combined with
US dollar differential contracts.
(ii) Natural gas For 2003, Provident paid $25.0 million to settle various natural gas market based contracts on an aggregate of 23,063,900 gigajoules ("GJ"). For 2002, Provident received $6.6 million to settle various natural gas market based contracts on an aggregate of 11,554,250 gigajoules ("GJ"). As at December 31, 2003 the estimated value of contracts in place settled at market prices at December 31 would have resulted in an opportunity cost of $4.1 million (December 31, 2002 -of $12.4 million). The contracts in place at December 31, 2003 are summarized in the following table:
Year Product Volume Terms Effective Period
---------------------------------------------------------------------
2004 Natural 5,000 Gjpd Cdn$4.95 per gj January 1 -
Gas(2) December 31
---------------------------------------------------------------------
9,000 Gjpd Cdn$6.36 per gj January 1 -
March 31
---------------------------------------------------------------------
900 Gjpd Cdn$5.75 per gj January 1 -
October 31
---------------------------------------------------------------------
27,000 Gjpd Cdn$5.10 per gj April 1 -
October 31
---------------------------------------------------------------------
3,600 Gjpd Cdn$5.82 per gj November 1 -
December 31
---------------------------------------------------------------------
10,000 Gjpd Funded Collar January 1 -
Cdn$5.50 - $8.75 March 31
per gj
---------------------------------------------------------------------
10,000 Gjpd Costless collar January 1 -
Cdn$5.50 - $7.85 March 31
per gj
---------------------------------------------------------------------
5,000 Gjpd Costless collar January 1 -
Cdn$6.00 - $7.28 March 31
per gj
---------------------------------------------------------------------
5,000 Gjpd Costless collar January 1 -
Cdn$6.25 - $8.00 March 31
per gj
---------------------------------------------------------------------
3,000 Gjpd Costless collar April 1 -
Cdn$5.50 - $6.23 December 31
per gj
---------------------------------------------------------------------
3,000 Gjpd Costless collar November 1 -
Cdn$5.25 - $7.10 December 31
per gj
---------------------------------------------------------------------
2,000 Gjpd Costless collar November 1 -
Cdn$5.50 - $7.29 December 31
per gj
---------------------------------------------------------------------
---------------------------------------------------------------------
2005 Natural 3,000 Gjpd Cdn$5.90 per gj January 1 -
Gas (2) March 31
---------------------------------------------------------------------
600 Gjpd Cdn$5.39 per gj January 1 -
October 31
---------------------------------------------------------------------
3,000 Gjpd Costless collar January 1 -
Cdn$5.25 - $7.10 March 31
per gj
---------------------------------------------------------------------
2,000 Gjpd Costless collar January 1 -
Cdn$5.50 - $7.29 March 31
per gj
---------------------------------------------------------------------
---------------------------------------------------------------------
(2) Natural gas contracts are settled against AECO monthly index.
(b) Foreign exchange contracts Provident had two foreign exchange sell contracts in place in 2003 for a total of US$1.25 million per month at an average exchange rate of Cdn$1.56 per US$1. 18. Cash reserve for future site reclamation Provident established a cash reserve effective May 1, 2001 for future site reclamation expenditures. In accordance with the royalty agreement, Provident funds the reserve by paying $0.25 per barrel of oil equivalent produced on a 6:1 basis into a segregated cash account. Actual expenditures incurred are then funded from the cash in this account. For the year ended December 31, 2003, $2.5 million was contributed to the reserve and actual expenditures totaled $2.2 million. For the year ended December 31, 2002, $1.3 million was added to the cash reserve and actual expenditures totaled $0.6 million. 19. Subsequent Event On February 4, 2004 the Trust issued 4,500,000 Trust units at $11.20 per unit for proceeds of $50.4 million ($47.9 million net of issue costs) pursuant to a public offering prospectus dated January 22, 2004. 20. Comparative balances Certain comparative numbers have been restated to conform with the current year presentation. |
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