Provident Energy Announces Third Quarter 2007 Results
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) (NYSE: PVX) today announces third quarter 2007 results.
“Provident’s third quarter results illustrate the value of our diversified energy portfolio for unitholders, as we increased production and maintained stable distributions in the face of persistently weak natural gas prices and a rising Canadian dollar,” said Provident President and Chief Executive Officer, Tom Buchanan. “Our U.S. MLP, BreitBurn Energy Partners, is executing on its growth strategy with a major acquisition of long-life natural gas assets in the northeastern U.S. We also continue to strengthen the Canadian oil and gas production business, recently announcing a high quality oil acquisition in southeast Saskatchewan. In the Midstream business, strong operational performance and low natural gas prices enabled us to build low cost product inventories through the quarter that will be sold in the coming winter heating season.”
Highlights
– Total funds flow from operations of $105 million ($0.43 per unit) for the quarter underpinned stable distributions. The negative impact of weak natural gas prices and the rising Canadian dollar in the third quarter were partially offset by strong oil prices, higher production and midstream frac spreads.
– Consolidated oil and gas production in the third quarter increased by 26 percent over 2006 to 38,800 boe per day, which includes the results of acquisition and drilling success in Canada and acquisitions in the U.S.
– Provident’s MLP subsidiary, BreitBurn Energy Partners, L.P., announced a transforming U.S. $1.47 billion acquisition of long-life natural gas assets in Michigan, demonstrating the continuing success of the U.S. growth strategy.
– The Canadian Oil and Gas Production business again delivered strong production, up nine percent from the second quarter to 28,000 barrels of oil equivalent per day, reflecting the Dixonville acquisition and positive drilling results in Northwest Alberta. Dixonville oil production is increasing as expected as the drilling program is implemented.
– Midstream EBITDA of $47 million for the quarter was impacted by a realized opportunity cost from the commodity price risk management program of $23 million, reflecting the very strong frac spread ratio during the quarter. The Midstream plants and facilities are performing well, and the business is well positioned for a strong fourth quarter, assuming a normal winter heating season, as low-cost inventories produced in the third quarter are sold into strengthening product markets.
– The net loss for the quarter of $35 million ($0.14 per unit) is largely due to non-cash unrealized financial derivative losses on the commodity price risk management program of $56 million. Net earnings by quarter fluctuate considerably as all future unrealized gains or losses on the five year program are recorded against current period results.
– Declared distributions during the third quarter of 2007 of $88 million ($0.36 per unit), representing a sustained monthly distribution of $0.12 per unit for the last 47 months.
Consolidated financial highlights Consolidated ($ 000s except Three months ended Nine months ended per unit data) September 30, September 30, —————————————————————————- % % 2007 2006 Change 2007 2006 Change —————————————————————————- Revenue (net of royalties and financial derivative instruments) $ 533,249 $ 661,022 (19) $1,625,392 $ 1,639,167 (1) —————————————————————————- Funds flow from COGP operations(1) $ 47,143 $ 41,315 14 $ 145,585 $ 136,754 6 Funds flow from USOGP operations (1)(3) 25,656 20,156 27 43,784 49,397 (11) Funds flow from Midstream operations(1) 32,350 58,618 (45) 101,323 123,834 (18) —————————————————————————- Total funds flow from operations(1) $ 105,149 $ 120,089 (12) $ 290,692 $ 309,985 (6) —————————————————————————- Per weighted average unit – basic $ 0.43 $ 0.61 (30) $ 1.30 $ 1.61 (19) Per weighted average unit – diluted(2) $ 0.43 $ 0.57 (25) $ 1.30 $ 1.58 (18) Distributions to unitholders $ 87,782 $ 70,970 24 $ 244,289 $ 207,892 18 Per unit $ 0.36 $ 0.36 – $ 1.08 $ 1.08 – Percent of funds flow from operations paid out as declared distributions(4) 89% 59% 51 88% 67% 31 Net (loss) income(5) $ (35,005) $ 120,850 – $ (38,111) $ 166,421 – Per weighted average unit – basic $ (0.14) $ 0.61 – $ (0.17) $ 0.87 – Per weighted average unit – diluted(2) $ (0.14) $ 0.58 – $ (0.17) $ 0.86 – Capital expenditures $ 54,317 $ 38,254 42 $ 153,757 $ 129,522 19 Capitol Energy acquisition $ – $ – $ 467,850 $ – Oil and gas property acquisitions, net $ 2,260 $ 472,731 $ 262,413 $ 472,947 Weighted average trust units outstanding (000s) – Basic 243,600 197,156 24 224,174 192,180 17 – Diluted(2) 243,775 220,362 11 224,349 199,768 12 —————————————————————————- —————————————————————————- Consolidated —————————————————————————- As at As at September 30, December 31, ($ 000s) 2007 2006 % Change —————————————————————————- Capitalization Long-term debt $1,217,136 $ 988,785 23 Unitholders’ equity $1,634,459 $1,542,974 6 —————————————————————————- —————————————————————————- (1) Represents cash flow from operations before changes in working capital and site restoration expenditures. (2) Includes dilutive impact of unit options, exchangeable shares and convertible debentures. (3) Year-to-date 2007 funds flow from USOGP operations includes $13.8 million (2006 – $4.9 million) of payments related to unit based compensation expensed in the 2006 fiscal year and paid in 2007. (4) Calculated as distributions to unitholders divided by funds flow from operations less distributions to non-controlling interests of $13.7 million year-to-date and $6.6 million for the quarter (2006 – $1.8 million and $0.7 million, respectively). (5) Net (loss) income for the nine months ended September 30, 2007 includes a future income tax charge of $105.7 million relating to the enactment of Bill C-52, Budget Implementation Act 2007 by the Canadian government. Operational highlights Consolidated Three months ended Nine months ended September 30, September 30, —————————————————————————- % % 2007 2006 Change 2007 2006 Change —————————————————————————- Oil and Gas Production Daily production Light/medium crude oil (bpd) 19,289 13,955 38 16,323 14,185 15 Heavy oil (bpd) 2,324 2,004 16 1,973 2,125 (7) Natural gas liquids (bpd) 1,281 1,326 (3) 1,356 1,443 (6) Natural gas (mcfpd) 95,588 80,991 18 94,505 79,792 18 —————————————————————————- Oil equivalent (boed)(1) 38,825 30,784 26 35,403 31,052 14 —————————————————————————- Average realized price (before realized financial derivative instruments) Light/medium crude oil ($/bbl) $ 64.59 $ 62.95 3 $ 60.89 $ 62.22 (2) Heavy oil ($/bbl) $ 45.34 $ 48.15 (6) $ 41.39 $ 40.10 3 Corporate oil blend ($/bbl) $ 62.52 $ 61.10 2 $ 58.76 $ 59.34 (1) Natural gas liquids ($/bbl) $ 55.22 $ 52.03 6 $ 52.11 $ 53.40 (2) Natural gas ($/mcf) $ 4.95 $ 5.88 (16) $ 6.54 $ 6.64 (2) —————————————————————————- Oil equivalent ($/boe)(1) $ 48.82 $ 49.40 (1) $ 49.75 $ 50.72 (2) —————————————————————————- Field netback (before realized financial derivative instruments) ($/boe) $ 26.08 $ 28.26 (8) $ 27.34 $ 29.39 (7) Field netback (including realized financial derivative instruments) ($/boe) $ 26.12 $ 28.17 (7) $ 27.56 $ 29.01 (5) —————————————————————————- Midstream Midstream NGL sales volumes (bpd) 112,386 114,839 (2) 115,664 115,228 – EBITDA (000s)(2) $ 47,425 $ 65,958 (28) $136,252 $145,209 (6) —————————————————————————- —————————————————————————- (1) Provident reports oil equivalent production converting natural gas to oil on a 6:1 basis. (2) EBITDA is earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items. See “Reconciliation of non-GAAP measures”.
Management’s discussion and analysis
The following analysis dated November 8, 2007 provides a detailed explanation of Provident Energy Trust’s (“Provident’s”) operating results for the three and nine months ended September 30, 2007 compared to the same time periods in 2006 and should be read in conjunction with the consolidated financial statements of Provident, found later in the interim report.
Provident Energy Trust has diversified investments in certain segments of the energy value chain. Provident currently operates in three key business segments: Canadian crude oil and natural gas production (“COGP”), United States crude oil and natural gas production, (“USOGP”) and Midstream. Provident’s COGP business produces crude oil and natural gas from seven core areas in the western Canadian sedimentary basin. USOGP produces crude oil and natural gas in California, Wyoming, Texas, and Florida, U.S.A. The Midstream business unit operates in Canada and the U.S.A. and extracts, processes, markets, transports and offers storage of natural gas liquids within the integrated facilities at Younger in British Columbia, Redwater and Empress in Alberta, Kerrobert in Saskatchewan, Sarnia in Ontario, Superior in Wisconsin and Lynchburg in Virginia.
This analysis commences with a summary of the consolidated financial and operating results followed by segmented reporting on the COGP business unit, the USOGP business unit and the Midstream business unit. The reporting focuses on the financial and operating measurements management uses in making business decisions and evaluating performance.
This analysis contains forward-looking information and statements. See “Forward-looking statements” at the end of the analysis for further discussion.
Third quarter and nine months ended September 30, 2007 highlights
The third quarter highlights section provides commentary for the third quarter and for the nine months ended September 30, 2007 results compared to the corresponding periods in 2006.
Consolidated funds flow from operations and cash distributions Consolidated ($ 000s except Three months ended Nine months ended per unit data) September 30, September 30, —————————————————————————- % % 2007 2006 Change 2007 2006 Change —————————————————————————- Revenue, Funds Flow from Operations and Distributions Revenue (net of royalties and financial derivative instruments $ 533,249 $ 661,022 (19) $1,625,392 $1,639,167 (1) —————————————————————————- Funds flow from operations $ 105,149 $ 120,089 (12) $ 290,692 $ 309,985 (6) Per weighted average unit – basic $ 0.43 $ 0.61 (30) $ 1.30 $ 1.61 (19) Per weighted average unit – diluted (1) $ 0.43 $ 0.57 (25) $ 1.30 $ 1.58 (18) —————————————————————————- Declared distributions $ 87,782 $ 70,970 24 $ 244,289 $ 207,892 18 Per Unit 0.36 0.36 – 1.08 1.08 – Percent of funds flow from operations distributed(2) 89% 59% 51 88% 67% 31 —————————————————————————- (1) Includes dilutive impact of unit options, exchangeable shares and convertible debentures. (2) Calculated as declared distributions to unitholders divided by funds flow from operations less distributions to non-controlling interests of $13.7 million year-to-date and $6.6 million for the quarter (2006 – $1.8 million and $0.7 million, respectively).
Management uses funds flow from operations to analyze operating performance. Funds flow from operations represents cash flow from operations before changes in working capital and site restoration expenditures. Provident also reviews funds flow from operations in setting monthly distributions and takes into account cash required for debt repayment and/or capital programs in establishing the amount to be distributed.
Funds flow from operations as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and therefore it may not be comparable with the calculations of similar measures for other entities. Funds flow from operations as presented is not intended to represent operating cash flow from operations or operating profits for the period nor should it be viewed as an alternative to cash provided by operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds flow from operations throughout this report are based on cash provided by operating activities before changes in non-cash working capital and site restoration expenditures.
Third quarter 2007 funds flow from operations was $105.1 million, 12 percent below the $120.1 million recorded in the third quarter of 2006. For the nine month period ended September 30, 2007 funds flow from operations was $290.7 million, six percent below the $310.0 million in the same period of 2006. COGP provided 45 percent of third quarter 2007 funds flow from operations, Midstream added 31 percent and USOGP generated the remaining 24 percent.
COGP 2007 third quarter funds flow from operations was $47.1 million, a 14 percent increase from the $41.3 million recorded in the comparable 2006 quarter. This increase was a result of higher crude oil and natural gas production due to the Capitol and Rainbow asset acquisitions and the internal development program, partially offset by lower realized natural gas prices, higher operating costs per boe and wider heavy oil differentials. For the nine month period ended September 30, 2007 COGP funds flow from operations was $145.6 million, a six percent improvement above the $136.8 million recorded in the comparable 2006 period.
The Midstream business unit added $32.4 million to third quarter 2007 funds flow from operations, 45 percent below the $58.6 million recorded in the comparable 2006 quarter, reflecting a seven percent reduction in gross operating margin, a $12.4 million increase in the realized loss on financial derivative instruments and higher interest and taxes. Typically in the Midstream business, the first and fourth quarters of the year generate considerably stronger funds flow from operations than the second and third quarters due to seasonality of product demand. For the nine months ended September 30, 2007, Midstream contributed $101.3 million to funds flow from operations, an 18 percent decrease from the $123.8 million in the comparable 2006 period. The decrease in Midstream funds flow from operations was largely due to a $15.0 million increase in realized losses on financial derivative instruments year-to-date 2007 over 2006 combined with higher general and administrative costs, interest and taxes, partially offset by a six percent increase in gross operating margin. See “Commodity price risk management” for detail regarding the losses on financial derivative instruments.
Funds flow from operations from USOGP operations in the third quarter of 2007 was $25.6 million, 27 percent above the $20.2 million in the comparable 2006 quarter. The increase is primarily due to two oil and gas property acquisitions in the second quarter of 2007. USOGP funds flow from operations for the nine months ended September 30, 2007 was $43.8 million, 11 percent below the $49.4 million in the comparable 2006 period. The decrease in funds flow from operations was primarily due to $13.8 million (2006 – $4.9 million) in cash payments in 2007 for unit based compensation related to the 2006 fiscal year. The expenses were recorded as non-cash unit based compensation in 2006 and resulted in a decrease to funds flow from operations when paid in 2007.
Declared distributions in the third quarter of 2007 totaled $87.8 million compared to $71.0 million of declared distributions in 2006. This represented 89 percent and 59 percent of funds flow from operations, respectively, after distributions to non-controlling interests of $6.6 million (2006 – $0.7 million). On a segmented basis, the Midstream business, due to its low sustaining capital requirements, effectively contributed 95 percent of its funds flow from operations for distribution in the three months ended September 30, 2007. The remaining distributions were effectively contributed by the oil and natural gas production businesses representing 86 percent of its funds flow from operations in the third quarter of 2007.
Outlook
Management currently anticipates better financial results in the fourth quarter than the third quarter of 2007, as upstream production continues to increase and the midstream business enters what is typically the strongest quarter of the year. While persistent natural gas price weakness remains a concern for the upstream businesses, low gas prices have enabled the Midstream business to build inexpensive inventory. Crude oil prices are approaching record highs, although the rising Canadian dollar mitigates that gain. These offsetting factors illustrate the ability of Provident’s diversified business to generate sustainable cash flow and stable distributions in spite of business environment volatility. The strong Canadian dollar is positive for U.S. unitholders, who see a resulting increase in distributions.
Long-term strategic planning remains a key focus for Provident management given the planned tax on income trust distributions that the Canadian federal government intends to implement beginning in 2011. The rules around the tax administration remain unclear, so it is difficult to estimate the impact on Provident with precision. While examining potential future scenarios, management’s current focus is on ensuring day-to-day operational excellence and continuing to build growth opportunities within all three business units, so that each is a strong, competitive business in its own right.
The Canadian Oil and Gas Production business unit has had an excellent year, highlighted by strong drilling and production results and two acquisitions of high quality assets (the Dixonville acquisition in May and the recently announced southeast Saskatchewan acquisition). The current weakness in natural gas prices and uncertainty in the business environment due to impending trust taxation and the announced Alberta royalty changes are generating acquisition opportunities. Provident will continue to assess long life, high quality assets that fit with our current portfolio. With strong operational performance to date and the anticipated completion of the southeast Saskatchewan acquisition, Provident now expects full year 2007 COGP production to meet the high end of the current production guidance, which is 26,400 boed.
Provident’s U.S. Oil and Gas Production business continues to grow, as BreitBurn Energy Partners L.P. takes advantage of its competitive cost of capital to pursue accretive acquisitions. The recent Quicksilver acquisition will vault the MLP into a leading position among the U.S. oil and gas master limited partnerships. While Provident’s interest in the MLP has been reduced to 22 percent, the Trust benefits both from the increased market value of the MLP and from its projected increase in quarterly distributions. With two months of production anticipated from the Quicksilver assets in 2007, Provident now anticipates that total U.S. production for 2007 will exceed previous production guidance of 9,500 to 10,000 boed.
The Midstream business continues to generate strong EBITDA and funds flow, mitigated somewhat by significant opportunity costs from the commodity price risk management program in the current business environment of low natural gas prices and high oil prices. The business is very well positioned for the fourth quarter, as inventories of low-cost natural gas liquids have been building over the summer months for sale into the seasonally stronger markets for propane and butane. With strategically located long-life facilities, storage capacity, multiple transportation choices and in-house marketing expertise, the Midstream business has flexibility and optionality. Assuming that seasonal product demand follows typical patterns, the Midstream business remains on track to generate 2007 EBITDA generally comparable to that in 2006.
On October 25, 2007, the Alberta provincial government announced a proposed new royalty regime for Alberta oil and gas production, to take effect on January 1, 2009. While the new regime will generally increase royalties on conventional oil and gas production, it is also sensitive to commodity pricing and to production per well. Management expects that Provident’s diversified portfolio will mitigate the impact of the new regime on the Trust, given that more than 60 percent of total funds flow from operations comes from midstream operations and operations outside Alberta. However, future drilling programs in Alberta may be impacted as Provident and partner companies reassess the economics of their Alberta assets.
Restatement of 2007 interim consolidated financial statements
In the third quarter of 2007, Provident determined that an adjustment was necessary principally due to commercial transactions within the Midstream segment that resulted in overstated inventory balances. Internal accounting controls identified the issue. Related cash settlements with third parties were not affected. Management has studied the systems and procedures involved and has taken remedial steps to strengthen the internal controls over these systems and procedures.
The effect of the restatement on the interim consolidated financial statements for the first and second quarters of 2007 is summarized below. There is no effect on 2006 or prior periods.
Effect on Effect on Effect on the three the three the six months ended months ended months ended (000′s) March 31, 2007 June 30, 2007 June 30, 2007 —————————————————————————- Increase in accounts receivable $ 3,138 $ 888 $ 4,026 (Decrease) in petroleum product inventory (13,226) (8,095) (21,321) Decrease in future income tax liability 2,875 2,054 4,929 —————————————————————————- (Decrease) in unitholders’ equity $ (7,213) $ (5,153) $ (12,366) —————————————————————————- —————————————————————————- (Increase) in cost of goods sold $(10,088) $ (7,207) $ (17,295) Decrease in future income tax expense 2,875 2,054 4,929 —————————————————————————- (Decrease) in net income $ (7,213) $ (5,153) $ (12,366) —————————————————————————- —————————————————————————- (Decrease) in net income per unit – basic and diluted $ (0.04) $ (0.02) $ (0.05) —————————————————————————- —————————————————————————- Decrease in funds flow from operations $(10,088) $ (7,207) $ (17,295) Change in non-cash working capital 10,088 7,207 17,295 Percentage of funds flow from operations distributed – originally reported 82% 79% 80% Percentage of funds flow from operations distributed – restated 91% 85% 88% —————————————————————————- —————————————————————————-
Taxation of trust income
In 2007, future income tax expense includes $105.7 million relating to the enactment of Bill C-52, Budget Implementation Act 2007 by the Canadian government. This bill contains legislation to tax publicly traded trusts including Provident. As a result of this legislation, the Trust is now required to record the future tax effect of the temporary differences on its flow through entities that are expected to reverse subsequent to 2010. The Trust has recorded the future income tax provision relating to this legislation as a rate change resulting in incremental future income tax expense of $105.7 million in 2007.
Until June 2007 the Trust had been reflecting the impact of certain taxable temporary differences in flow through entities at a nil tax rate on the assumption that the Trust would make sufficient tax deductible cash distributions to unitholders such that the Trust’s taxable income would be nil for the foreseeable future. The new legislation limits the tax deductibility of cash distributions such that income taxes may become payable in the future.
The Trust has estimated its future income taxes based on estimates of results of operations and tax pool claims and cash distributions in the future assuming no material change to the Trust’s current organizational structure. The Trust’s estimate of future income taxes does not incorporate any assumptions related to a change in organizational structure until such structures are given legal effect.
The Trust’s estimate of its future income taxes will vary as do the Trust’s assumptions pertaining to the factors described above, and such variations may be material.
The new legislation will not affect the Trust’s cash flows from operations and accordingly the Trust’s financial condition until 2011, based on our planned compliance with the legislated growth guidelines.
The Trust has approximately $1.3 billion in tax pools available to claim against taxable income. Provident plans to manage discretionary tax pool claims to defer payment of current taxes as long as possible. Provident has made estimates of future current taxability based on a number of assumptions including: future product prices; future production and sales; future operating and product costs; future general and administrative costs; future capital expenditures; and general business conditions. Using these assumptions about future events which may or may not occur, Provident estimates that:
– current taxes on oil and gas operations would occur after 2016; and
– current taxes for midstream operations would occur in 2011.
Net (loss) income Consolidated Three months ended Nine months ended September 30, September 30, —————————————————————————- ($ 000s except % % per unit data) 2007 2006 Change 2007 2006 Change —————————————————————————- Net (loss) income $ (35,005) $ 120,850 – $ (38,111) $ 166,421 – Per weighted average unit – basic (1) $ (0.14) $ 0.61 – $ (0.17) $ 0.87 – Per weighted average unit – diluted(2) $ (0.14) $ 0.58 – $ (0.17) $ 0.86 – —————————————————————————- —————————————————————————- (1) Based on weighted average number of trust units outstanding. (2) Based on weighted average number of trust units outstanding including the dilutive impact of the unit option plan, exchangeable shares and convertible debentures.
Net loss for the third quarter of 2007 was $35.0 million compared to $120.9 million of net income in the comparable 2006 quarter. On a consolidated basis, favorable operating results were more than offset by a $141.0 million change in unrealized loss on financial derivative instruments and increased depletion, depreciation and accretion.
The COGP business segment’s net loss was $17.8 million, a decrease of $40.4 million compared to the 2006 third quarter net income of $22.6 million. The decrease was mainly due to increased depletion, depreciation, and accretion resulting from the acquisitions of Capitol on June 19, 2007 and the Rainbow assets on August 31, 2006, and unrealized losses on financial derivative instruments compared to unrealized gains in the third quarter of 2006, partially offset by increased operating earnings.
The Midstream segment’s net loss was $8.6 million in the third quarter of 2007 as compared to $82.7 million net income in the third quarter of 2006. The loss was primarily attributable to the impact of the commodity price risk management program. The third quarter of 2007 saw a $12.4 million increase in realized losses on financial derivative instruments. As well, the $30.9 million unrealized losses on financial derivative instruments in the third quarter of 2007 represents a $78.3 million change from the $47.4 million unrealized gain in the third quarter of 2006.
In the third quarter of 2007, USOGP’s net loss was $8.6 million as compared to 2006 third quarter net income of $15.5 million. Increased operating earnings were more than offset by a $23.9 million unrealized loss on financial derivative instruments in the third quarter of 2007, compared to a $23.0 million unrealized gain in the third quarter of 2006. The 2007 unrealized loss includes $12.0 million associated with deal contingent, natural gas, 3.5 year, commodity swaps entered into to support the U.S. acquisition, which closed on November 1, 2007.
The significant swing in Provident’s net income year-over-year illustrates the extent to which quarterly net income figures are impacted by the requirement to “mark to market” all unrealized gains and losses associated with financial derivative instruments at a point in time and report these against current period income. Because Provident’s commodity price risk management program extends up to five years into the future in the Midstream segment, net earnings can show substantial quarterly variation that is not necessarily related to current operations.
Reconciliation of non-GAAP measures
The Trust calculates earnings before interest, taxes, depletion and accretion and other non-cash items (EBITDA) within its segment disclosure. EBITDA is a non-GAAP measure. A reconciliation between EBITDA and income (loss) before taxes and non-controlling interests follows:
EBITDA Reconciliation Three months ended Nine months ended September 30, September 30, —————————————————————————- % % 2007 2006 Change 2007 2006 Change —————————————————————————- EBITDA $ 129,948 $ 133,708 (3) $ $349,294 354,970 (2) Adjusted for: Dilution gain – – – 98,592 – – Interest and non-cash expenses excluding unrealized (loss) gain on financial derivative instruments and dilution gain (126,661) (76,974) 65 (317,883) (218,687) 45 Unrealized (loss) gain on financial derivative instruments (56,242) 84,737 – (80,314) (19,021) 322 —————————————————————————- (Loss) income before taxes and non- controlling interests $ (52,955) $ 141,471 – $ 49,689 $ 117,262 (58) —————————————————————————- —————————————————————————- Reconciliation of funds flow from operations Three months ended Nine months ended to distributions September 30, September 30, —————————————————————————- % % 2007 2006 Change 2007 2006 Change —————————————————————————- Cash provided by operating activities $ 90,655 $ 69,928 30 $ 327,125 $ 251,460 30 Change in non-cash operating working capital 13,904 48,904 (72) (38,773) 55,117 – Site restoration expenditures 590 1,257 (53) 2,340 3,408 (31) —————————————————————————- Funds flow from operations 105,149 120,089 (12) 290,692 309,985 (6) Distributions to non- controlling interests (6,583) (698) 843 (13,722) (1,808) 659 Cash retained for financing and investing activities (10,784) (48,421) (78) (32,681) (100,285) (67) —————————————————————————- Distributions to unitholders 87,782 70,970 24 244,289 207,892 18 Accumulated cash distributions, beginning of period 1,083,332 780,282 39 926,825 643,360 44 —————————————————————————- Accumulated cash distributions, end of period $1,171,114 $851,252 38 $1,171,114 $ 851,252 38 —————————————————————————- Cash distributions per unit $ 0.36 $ 0.36 – $ 1.08 $ 1.08 – —————————————————————————- —————————————————————————- Taxes Consolidated Three months ended Nine months ended September 30, September 30, —————————————————————————- ($ 000s) % % 2007 2006 Change 2007 2006 Change —————————————————————————- Capital tax expense $ 2,364 $ 259 813 $ 3,252 $ 862 277 Current and withholding tax expense (recovery) 3,493 (1,328) – 6,623 4,396 51 Future income tax (recovery) expense (19,302) 19,406 – 88,080 (55,569) – —————————————————————————- $ (13,445) $ 18,337 – $ 97,955 $ (50,311) – —————————————————————————-
For the nine months ended September 30, 2007, the total income tax expense was $98.0 million. Based on year-to-date income before taxes and non-controlling interests of $49.7 million, the expected income tax expense was $16.2 million. The main reason for the larger than expected income tax expense is $105.7 million of future income taxes recorded as a result of the enactment of legislation to tax publicly traded trusts in 2011 (see “Taxation of trust income”). The offsetting difference between the expected expense and the total tax expense is primarily a result of deductions allowed when computing taxable income of the Trust for distributions made to unitholders. The Trust is a taxable entity under Canadian income tax law and is currently taxable only on income that is not distributed or distributable to the unitholders until 2011, when the new tax on distributions is in effect. If the Trust distributes all of its taxable income to the unitholders, no current provision for taxes is required by the Trust until 2011. Since inception, the Trust has distributed all of its taxable income to the unitholders. Additionally, interest and royalties are charged by the Trust to its subsidiaries, which are deductible in the computation of taxable income at the incorporated subsidiary level reducing tax pool claims in certain subsidiaries and potentially creating tax loss carry-forwards that result in future income tax recoveries.
Capital taxes in the third quarter totaled $2.4 million, an increase from the $0.3 million expense recorded in the third quarter of 2006, and $3.3 million year-to-date, compared to $0.9 million year-to-date for 2006. The increase is due to greater production subject to the Saskatchewan resource surcharge as well as adjustments made upon filing of tax returns.
The current and withholding tax expense of $3.5 million in the third quarter of 2007 compares to a recovery of $1.3 million in the third quarter of 2006. The majority of these taxes arise from Provident’s U.S.-based operations and 2007 withholding taxes reflect additional distributions in the third quarter of 2007. For the nine months ended September 30, 2007, current and withholding taxes total $6.6 million, compared with $4.4 million in 2006. The increase in current taxes was due to U.S.-based Midstream operations.
The 2007 third quarter future income tax recovery of $19.3 million compares to an expense of $19.4 million in the third quarter of 2006. The recovery is primarily a result of increased tax loss carry forwards generated from interest and royalties charged by the Trust to its subsidiaries. For the nine months ended September 30, 2007, future income tax expense was $88.1 million, compared with a recovery of $55.6 million in 2006. The 2007 expense includes $105.7 million relating to the second quarter enactment of legislation to tax publicly traded trust in 2011.
Provident’s tax pools available to shelter future income as at September 30, 2007 are estimated as follows: As at September 30, 2007 —————————————————————————- ($ 000s) COGP USOGP (1) Midstream Total —————————————————————————- Intangibles $ 490,000 $ 60,000 $ – $ 550,000 Tangibles 260,000 65,000 280,000 605,000 Non-capital losses 120,000 – 65,000 185,000 —————————————————————————- $ 870,000 $ 125,000 $ 345,000 $1,340,000 —————————————————————————- —————————————————————————- (1) Non-Canadian tax pools Provident also has capital losses of approximately $435 million which are available to reduce the tax effect of future capital gains. Interest expense Consolidated Three months ended Nine months ended September 30, September 30, —————————————————————————- ($ 000s, except) % % as noted) 2007 2006 Change 2007 2006 Change —————————————————————————- —————————————————————————- Interest on bank debt $ 13,445 $ 9,334 44 $ 32,066 $ 23,504 36 Weighted- average interest rate on bank debt 5.6% 5.6% – 5.5% 5.3% 4 Interest on 8.75% convertible debentures 466 626 (26) 1,605 2,016 (20) Interest on 8.0% convertible debentures 502 632 (21) 1,471 1,957 (25) Interest on 6.5% convertible debentures 1,609 1,610 – 4,827 4,828 – Interest on 6.5% convertible debentures 2,437 2,438 – 7,311 7,278 – —————————————————————————- Total cash interest $ 18,459 $ 14,640 26 $ 47,280 $ 39,583 19 —————————————————————————- —————————————————————————- Weighted average interest rate on all long-term debt 5.9% 6.0% (2) 5.8% 5.8% – Debenture accretion and other non-cash interest expense 1,786 666 168 5,416 2,040 165 —————————————————————————- Total interest expense $ 20,245 $ 15,306 32 $ 52,696 $ 41,623 27 —————————————————————————- —————————————————————————-
Interest on bank debt increased in 2007 compared to 2006 due to increased capitalization including debt levels, largely resulting from the Rainbow asset acquisition in the third quarter of 2006 and the Capitol acquisition in the second quarter of 2007.
Commodity price risk management program
The Trust executes a commodity price risk management program that is designed to limit the Trust’s exposure to downturns in commodity prices and to protect monthly cash distributions and support the Trust’s capital program. Our risk management strategy generally uses structures that provide a floor price while allowing upside participation in a rising commodity price market.
In accordance with the Trust’s credit policy, the Trust mitigates associated credit risk by limiting financial derivative transactions to counterparties within approved credit limits.
In the Midstream business, production margins are affected by the spread between the purchase cost of natural gas and sales price of propane, butane and condensate. Financial market liquidity may not provide sufficient or adequate opportunity to directly hedge propane, butane and condensate prices over the longer term. Prices for propane, butane and condensate historically have correlated with prices for crude oil. As a consequence, Provident has entered into natural gas and crude oil financial derivative contracts through 2012 in order to protect operating margins in the Midstream business. Short term financial derivative instruments directly fixing propane and butane prices have also been executed.
Activity in the Third Quarter A summary of Provident’s risk management contracts executed during the third quarter of 2007 is contained in the following tables: COGP Volume Effective Year Product (Buy)/Sell Terms Period —————————————————————————- 2007 Crude 525 Bpd Puts US $64.57 per bbl October 1 – Oil December 31 125 Bpd Participating Swap US $65.00 per bbl October 1 – (max to 95% above the floor price) December 31 2008 250 Bpd Puts US $63.75 per bbl January 1 – December 31 250 Bpd Participating Swap US $60.00 per bbl January 1 – (75.3% above the floor price) December 31 125 Bpd Participating Swap US $65.00 per bbl January 1 – (50.4% above the floor price) December 31 325 Bpd Participating Swap US $67.20 per bbl July 1 – (70% above the floor price) December 31 2009 125 Bpd Participating Swap US $60.00 per bbl January 1 – (60% above the floor price) December 31 425 Bpd Participating Swap US $62.50 per bbl January 1 – (55.2% above the floor price) December 31 2007 Natural 7,750 Gjpd Puts Cdn $4.78 per gj October 1 – Gas October 31 1,000 Gjpd Participating Swap Cdn $5.00 per gj October 1 – (51% above the floor price) October 31 2008 1,000 Gjpd Puts Cdn $6.00 per gj January 1 – March 31 5,000 Gjpd Participating Swap Cdn $6.48 per gj January 1 – (max up to 100% above the floor price) March 31 2,000 Gjpd Participating Swap Cdn $6.00 per gj January 1 – (max up to 85% above the floor price) October 31 2,000 Gjpd Participating Swap Cdn $6.00 per gj April 1 – (56% above the floor price) October 31 1,000 Gjpd Participating Swap Cdn $6.75 per gj April 1 – (51% above the floor price) December 31 1,000 Gjpd Participating Swap Cdn $7.00 per gj April 1 – (max up to 85% above the floor price) December 31 1,000 Gjpd Participating Swap Cdn $6.50 per gj November 1 – (50% above the floor price) December 31 1,000 Gjpd Participating Swap Cdn $6.50 per gj November 1 – (max up to 90% above the floor price) December 31 2,000 Gjpd Participating Swap Cdn $6.75 per gj November 1 – (max up to 90% above the floor price) December 31 2,000 Gjpd Participating Swap Cdn $7.00 per gj November 1 – (max up to 85% above the floor price) December 31 2,000 Gjpd Participating Swap Cdn $7.50 per gj November 1 – (max up to 100% above the floor price) December 31 2009 1,000 Gjpd Participating Swap Cdn $6.50 per gj January 1 – (50% above the floor price) March 31 1,000 Gjpd Participating Swap Cdn $6.50 per gj January 1 – (max up to 90% above the floor price) March 31 1,000 Gjpd Participating Swap Cdn $6.75 per gj January 1 – (51% above the floor price) March 31 2,000 Gjpd Participating Swap Cdn $6.75 per gj January 1 – (max up to 90% above the floor price) March 31 1,000 Gjpd Participating Swap Cdn $7.00 per gj January 1 – (max up to 85% above the floor price) March 31 2,000 Gjpd Participating Swap Cdn $7.00 per gj January 1 – (max up to 85% above the floor price) March 31 2,000 Gjpd Participating Swap Cdn $7.50 per gj January 1 – (max up to 100% above the floor price) March 31 —————————————————————————- —————————————————————————- USOGP Volume Effective Year Product (Buy)/Sell Terms Period —————————————————————————- 2007 Crude 125 Bpd Participating Swap US $62.50 per bbl October 1 – Oil (max up to 95% above the floor price) December 31 125 Bpd Participating Swap US $65.00 per bbl October 1 – (92.1% above the floor price) December 31 2008 125 Bpd Participating Swap US $60.00 per bbl January 1 – (78% above the floor price) December 31 125 Bpd Participating Swap US $65.00 per bbl January 1 – (57.5% above the floor price) December 31 790 Bpd US $72.89 per bbl (10) January 1 – December 31 2009 425 Bpd Participating Swap US $60.00 per bbl January 1 – (61.45% above the floor price) December 31 679 Bpd US $71.38 per bbl (10) January 1 – December 31 250 Bpd Participating Swap US $62.50 per bbl January 1 – (67.25% above the floor price) December 31 500 Bpd US $72.25 per bbl April 1 – June 30 250 Bpd US $72.47 per bbl October 1 – December 31 250 Bpd Participating Swap US $60.00 per bbl October 1 – (70% above the floor price) December 31 500 Bpd Participating Swap US $65.00 per bbl October 1 – (54% above the floor price) December 31 500 Bpd Participating Swap US $65.00 per bbl October 1 – (50% above the floor price) December 31 2010 609 Bpd US $70.42 per bbl (10) January 1 – December 31 250 Bpd Participating Swap US $62.50 per bbl January 1 – (56.20% above the floor price) December 31 250 Bpd Participating Swap US $60.00 per bbl January 1 – (70% above the floor price) June 30 500 Bpd Participating Swap US $65.00 per bbl January 1 – (50% above the floor price) June 30 250 Bpd US $72.47 per bbl January 1 – June 30 542 Bpd US $72.05 per bbl January 1 – July 31 2008 Natural 48,643 US $8.01 per mmbtu (11) January 1 – Gas Mmbtu December 31 2009 44,071 US $8.01 per mmbtu (11) January 1 – Mmbtu December 31 2010 40,471 US $8.01 per mmbtu (11) January 1 – Mmbtu December 31 2011 40,400 US $8.01 per mmbtu (11) January 1 – Mmbtu March 31 —————————————————————————- —————————————————————————- Midstream Volume Effective Year Product (Buy)/Sell Terms Period —————————————————————————- 2007 Crude (11,595)Bpd US $73.54 per bbl (4) October 1 – Oil December 31 1,613 Bpd US $77.53 per bbl (9) October 1 – October 31 1,667 Bpd US $77.66 per bbl (9) November 1 – November 30 806 Bpd US $77.97 per bbl (9) December 1 – December 31 Natural 2,500 Gjpd Cdn $6.11 per gj (9) November 1 – Gas November 30 Propane 11,543 Bpd US $1.2257 per gallon (4) (6) October 1 – December 31 1,630 Bpd US $1.2184 per gallon (6) (9) October 1 – December 31 Normal 815 Bpd US $1.4727 per gallon (7) (9) October 1 – Butane December 31 2,450 Bpd US $1.4299 per gallon (4) (7) October 1 – December 31 ISO 2,010 Bpd US $1.425 per gallon (4) (8) October 1 – Butane December 31 2008 Crude (845) Bpd US $74.64 per bbl (4) January 1 – Oil March 31 Propane 850 Bpd US $1.2487 per gallon (4) (6) January 1 – March 31 5,645 Bpd US $1.2829 per gallon (6) (9) January 1 – February 29 Normal 150 Bpd US $1.4325 per gallon (4) (7) January 1 – Butane March 31 ISO 150 Bpd US $1.4453 per gallon (4) (8) January 1 – Butane March 31 2009 Crude 712 Bpd Cdn $74.21 per bbl January 1 – Oil August 31 1,000 Bpd Participating Swap US $63.13 per bbl July 1 – (56% above the floor price) August 31 Natural (5,930) Cdn $7.32 per gj January 1 – Gas Gjpd August 31 Foreign Sell US $1,972,561 per month July 1 – Exchange @ 1.0245 (5) August 31 2010 Crude 1,552 Bpd Cdn $72.31 per bbl January 1 – Oil August 31 500 Bpd Participating Swap Cdn $61.50 per bbl July 1 – (50% above the floor price) August 31 Natural (9,687) Cdn $7.09 per gj January 1 – Gas Gjpd August 31 2012 Crude 2,171 Bpd Cdn $72.61 per bbl January 1 – Oil September 30 Natural (12,204) Cdn $7.02 per gj January 1 – Gas Gjpd September 30 —————————————————————————- —————————————————————————- Corporate Volume Effective Year Product (Buy)/Sell Terms Period —————————————————————————- 2007 Foreign Buy US $1,000,000 @ .9925 (5) October 5 Exchange 2007 Interest Pay fixed rate of 4.8852% – Receive July 1 – Rate 3M CAD BA on Cdn $50MM Notional (12) December 31 2008 Interest Pay fixed rate of 4.8852% – Receive January 1 – Rate 3M CAD BA on Cdn $50MM Notional (12) July 31 —————————————————————————- —————————————————————————- (1) The above table represents a number of transactions entered into over an extended period of time. (2) Natural Gas contracts are settled against AECO monthly index. (3) Crude Oil contracts are settled against NYMEX WTI calendar average. (4) Conversion of Crude Oil BTU hedges to liquids. (5) US dollar hedge contracts settled against Bank of Canada noon rate average. (6) Propane contracts are settled against Belvieu C3 TET. (7) Normal Butane contracts are settled against Belvieu NC4 NON-TET. (8) ISO Butane contracts are settled against Belvieu IC4 NON-TET. (9) Midstream inventory hedges. (10) Deal contingent commodity swap to support pending acquisition of Quicksilver assets. Crude Oil contracts settle against NYMEX WTI. (11) Deal contingent commodity swap to support pending acquisition of Quicksilver assets. Natural Gas contracts settle against Natural Gas – Michcon City Gate Inside FERC. (12) Settles quarterly against 3M CAD BA interest rate.
A summary of all of Provident’s contracts in place at September 30, 2007 is available on Provident’s website at www.providentenergy.com.
Settlement of commodity contracts
The following is a summary of the net funds flow from operations to settle commodity contracts during the third quarter of 2007. For comparative purposes the 2006 amounts are also summarized.
a) Crude oil
For the quarter ended September 30, 2007, Provident paid $5.8 million to settle various oil market based contracts on an aggregate volume of 1.0 million barrels. During the quarter ended September 30, 2006, Provident paid $2.9 million to settle various oil market based contracts on an aggregate volume of 0.7 million barrels. Strong oil prices during the quarter caused the opportunity cost on oil price risk management activities.
For the nine months ended September 30, 2007, Provident paid $2.4 million to settle various oil market based contracts on an aggregate volume of 2.3 million barrels. During the nine months ended September 30, 2006, Provident paid $7.0 million to settle various oil market based contracts on an aggregate volume of 1.6 million barrels.
It is estimated that if all contracts in place had been settled at September 30, 2007 an opportunity cost of $38.3 million (September 30, 2006 – $1.6 million) would have been incurred.
b) Natural Gas
For the quarter ended September 30, 2007, Provident received $5.9 million to settle various natural gas market based contracts on an aggregate volume of 4.6 million gj’s. Weak natural gas prices during the quarter caused the gain on natural gas price risk management activities. For comparison, during the quarter ended September 30, 2006, Provident received $2.7 million to settle various natural gas market based contracts on an aggregate of 1.4 million gj’s.
For the nine months ended September 30, 2007, Provident received $4.5 million to settle various natural gas market based contracts on an aggregate volume of 12.2 million gj’s. For comparison, during the nine months ended September 30, 2006, Provident received $3.8 million to settle various natural gas market based contracts on an aggregate of 4.8 million gj’s.
It is estimated that if contracts in place had been settled at September 30, 2007 an opportunity gain of $3.5 million (September 30, 2006 – $9.1 million) would have been incurred.
c) Midstream
For the quarter ended September 30, 2007 Provident received $5.2 million (2006 – paid $2.5 million) to settle Midstream oil market based contracts on an aggregate volume of 0.3 million barrels (2006 – 0.7 million barrels) and paid $19.5 million (2006 – $9.7 million) to settle Midstream natural gas market based contracts on an aggregate volume of 6.8 million gj’s (2006 – 5.4 million gj’s). A strong “frac spread ratio” between low natural gas prices and high crude oil prices caused this net opportunity cost. In addition, for the third quarter of 2007, Provident paid $9.0 million (2006 – received $1.2 million) to settle Midstream NGL market based contracts on an aggregate volume of 1.7 million barrels (2006 – 0.3 million barrels).
For the nine months ended September 30, 2007 Provident received $17.7 million (2006 – paid $4.2 million) to settle Midstream oil market based contracts on an aggregate volume of 0.8 million barrels (2006 – 1.2 million barrels) and paid $31.9 million (2006 – $18.3 million) to settle Midstream natural gas market based contracts on an aggregate volume of 18.7 million gj’s (2006 – 10.3 million gj’s). In addition, Provident paid $21.6 million (2006 – received $1.7 million) to settle Midstream NGL market based contracts on an aggregate volume of 4.8 million barrels (2006 – 0.7 million barrels).
It is estimated that if contracts in place had been settled at September 30, 2007 an opportunity cost of $99.9 million (September 30, 2006 – $40.1 million) would have been incurred. These unrealized “mark-to-market” opportunity costs relate to positions with effective periods ranging from 2007 through 2012 and are required to be recognized in the financial statements under generally accepted accounting principles. These unrealized opportunity costs relate to financial derivative instruments which were entered into in order to manage commodity prices and protect future Midstream product margins. Fluctuations in the market value of these instruments have no impact on funds flow from operations until the instrument is settled.
d) Foreign exchange contracts
For the quarter ended September 30, 2007, Provident received $1.8 million to settle various foreign exchange based contracts (2006 – paid $0.3 million).
For the nine months ended September 30, 2007, Provident received $1.3 million to settle various foreign exchange based contracts (2006 – $0.5 million). The foreign exchange gains have been included in note 12 as a component of foreign exchange gain and other and allocated to their respective business segments.
It is estimated that if contracts in place had been settled at September 30, 2007 an opportunity gain of $0.8 million (September 30, 2006 – nil) would have been incurred.
e) Interest rate contracts
As at September 30, 2007 the estimated value of contracts in place settled at September 30 interest rates was an opportunity cost of $0.1 million (September 30, 2006 – nil).
Goodwill
Goodwill represent