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| SE > SEC Filings for SE > Form 10-Q on 7-Aug-2009 | All Recent SEC Filings |
7-Aug-2009
Quarterly Report
INTRODUCTION
Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying Condensed Consolidated Financial Statements. As previously discussed, the 2008 data contained in the Condensed Consolidated Financial Statements and the related information presented in this report have been recast to reflect the reporting requirements of SFAS No. 160, which was adopted January 1, 2009, and to reflect the operating results of certain Western Canada Transmission & Processing natural gas gathering and processing facilities as discontinued operations. See Notes 6 and 21 of Notes to Condensed Consolidated Financial Statements for further discussion.
Executive Overview
For the three months ended June 30, 2009 and 2008, we reported net income from controlling interests of $140 million and $295 million, respectively. For the six months ended June 30, 2009 and 2008, we reported net income from controlling interests of $438 million and $662 million, respectively. The decrease for the three and six-month periods primarily reflects lower earnings from Field Services and Western Canada Transmission & Processing as a result of lower NGL prices associated with lower crude oil prices during the first six months of 2009. Crude oil averaged $51 per barrel for the six months ended June 30, 2009 versus $111 per barrel during the same period in 2008. The decrease in earnings was partially offset by the recognition of a $135 million deferred gain ($85 million after-tax) in the first quarter of 2009 associated with partnership units previously issued by DCP Partners.
The highlights for the three months and six months ended June 30, 2009 include:
• U.S. Transmission's earnings decreased due primarily to lower margins from gas processing in 2009 and a customer bankruptcy settlement in the second quarter of 2008, partially offset by earnings from expansion projects placed into service late in 2008 and in 2009 and lower project development costs,
• Distribution results reflect a weaker Canadian dollar and an earnings sharing settlement in the second quarter of 2009 related to prior year earnings, partially offset by higher storage and transportation revenues,
• Western Canada Transmission & Processing earnings decreased primarily as a result of lower NGL prices related to the Empress processing plant and a weaker Canadian dollar, partially offset by higher gathering and processing revenues,
• Field Services earnings reflect lower NGL and natural gas prices in 2009, partially offset by the recognition of a deferred gain associated with partnership units previously issued by DCP Partners, and
• Other reported lower expenses in the 2009 periods.
In the first six months of 2009, we reported $426 million of capital and investment expenditures, excluding the $295 million acquisition of NOARK. Approximately $1.1 billion is projected for the full year and includes expansion capital of approximately $600 million.
On February 13, 2009, in order to further protect our capitalization structure against a potential extreme decline in the Canadian dollar, we issued 32.2 million shares of our common stock and received net proceeds of $448 million.
As of June 30, 2009, we have approximately $2.6 billion in credit facilities and expect to continue to utilize commercial paper and revolving lines of credit, as needed, to fund our liquidity needs throughout 2009.
On May 4, 2009, Spectra Energy Partners acquired all of the ownership interests of NOARK from Atlas for approximately $295 million in cash. In the second quarter of 2009, Spectra Energy Partners issued 9.8 million limited partner units to the public and 0.2 million general partner units, resulting in net proceeds of $212 million and a reduction of our ownership interest in Spectra Energy Partners from 84% to 74%. The proceeds were used to partially repay the funds borrowed in connection with the acquisition. See Note 2 of Notes to Condensed Consolidated Financial Statements for further discussion.
RESULTS OF OPERATIONS
Three Months Six Months
Ended June 30, Ended June 30,
2009 2008 2009 2008
(in millions)
Operating revenues $ 937 $ 1,133 $ 2,321 $ 2,733
Operating expenses 620 822 1,589 1,929
Gains on sales of other assets and other, net - 32 10 32
Operating income 317 343 742 836
Other income and expenses 54 253 230 473
Interest expense 146 149 296 307
Earnings from continuing operations before income taxes 225 447 676 1,002
Income tax expense from continuing operations 67 136 206 308
Income from continuing operations 158 311 470 694
Income (loss) from discontinued operations, net of tax (1 ) (2 ) 2 1
Net income 157 309 472 695
Net income-noncontrolling interests 17 14 34 33
Net income-controlling interests $ 140 $ 295 $ 438 $ 662
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Three and Six Months Ended June 30, 2009 Compared to Same Periods in 2008
Operating Revenues. Operating revenues for the three and six months ended June 30, 2009 decreased by $196 million or 17% and $412 million or 15%, respectively, compared to the same periods in 2008. The decreases were driven primarily by:
• the effects of a weaker Canadian dollar on revenues at Western Canada Transmission & Processing and Distribution, and
• lower NGL prices associated with the Empress operations at Western Canada Transmission & Processing, partially offset by
• higher storage and transportation revenues at Distribution.
Operating Expenses. Operating expenses for the three and six months ended June 30, 2009 decreased by $202 million or 25% and $340 million or 18%, respectively, compared to the same periods in 2008. The decreases were driven primarily by:
• the effects of a weaker Canadian dollar at Western Canada Transmission & Processing and Distribution,
• lower prices of natural gas purchased for the Empress facility, and
• lower project development costs at U.S. Transmission.
Gains on Sales of Other Assets and Other, net. Gains on sales of other assets and other, net for the three and six months ended June 30, 2009 decreased $32 million and $22 million, respectively, compared to the same periods in 2008. The decreases were primarily due to a 2008 second quarter customer bankruptcy settlement.
Operating Income. Operating income for the three and six months ended June 30, 2009 decreased by $26 million, or 8%, and $94 million, or 11%, respectively, compared to the same periods in 2008 primarily due to lower NGL product prices associated with the Empress operations at Western Canada Transmission & Processing, a weaker Canadian dollar and a 2008 customer bankruptcy settlement at U.S. Transmission, partially offset by higher storage and transportation revenues at Distribution.
Other Income and Expenses. Other income and expenses for the three and six months ended June 30, 2009 decreased by $199 million, or 79%, and $243 million, or 51%, respectively, compared to the same periods in 2008. The decreases were attributable to lower equity in earnings from Field Services, reflecting primarily lower commodity prices, partially offset by a gain recognized in the first quarter of 2009 associated with partnership units previously issued by DCP Partners.
Income Tax Expense from Continuing Operations. Income tax expense from continuing operations for the three and six months ended June 30, 2009 decreased by $69 million and $102 million, respectively, compared to the same periods in 2008 as a result of decreased earnings from continuing operations. For the three months ended June 30, 2009, the effective tax rate was 29.8% compared to 30.4% for the same period in 2008. The effective tax rate for the six months ended June 30, 2009 was 30.5% compared to 30.7% in the same period in 2008.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.
Segment Results
We evaluate segment performance based on EBIT from continuing operations, after deducting noncontrolling interests related to those profits. On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of noncontrolling interests related to those profits. Cash, cash equivalents and investments are managed centrally, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the segments' EBIT. We consider segment EBIT to be a good indicator of each segment's operating performance from its continuing operations, as it represents the results of our ownership interests in operations without regard to financing methods or capital structures.
Our segment EBIT may not be comparable to similarly titled measures of another company because other entities may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table, and detailed discussions follow.
EBIT by Business Segment
Three Months Six Months
Ended June 30, Ended June 30,
2009 2008 2009 2008
(in millions)
U.S. Transmission $ 234 $ 244 $ 451 $ 470
Distribution 40 54 192 219
Western Canada Transmission & Processing 58 91 139 220
Field Services 24 216 174 408
Total reportable segment EBIT 356 605 956 1,317
Other (12 ) (28 ) (36 ) (48 )
Total reportable segment and other EBIT 344 577 920 1,269
Interest expense 146 149 296 307
Interest income and other (a) 27 19 52 40
Earnings from continuing operations before
income taxes. $ 225 $ 447 $ 676 $ 1,002
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(a) Includes foreign currency transaction gains and losses and the elimination of the noncontrolling interests related to EBIT.
Noncontrolling interests as presented in the following segment-level discussions includes only noncontrolling interests related to EBIT of non-wholly owned entities. It does not include noncontrolling interests related to interest and taxes of those operations. The amounts discussed below include intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements.
U.S. Transmission
Three Months Six Months
Ended June 30, Ended June 30,
Increase Increase
2009 2008 (Decrease) 2009 2008 (Decrease)
(in millions, except where noted)
Operating revenues $ 414 $ 400 $ 14 $ 819 $ 803 $ 16
Operating expenses
Operating, maintenance and other 121 151 (30 ) 264 277 (13 )
Depreciation and amortization 62 58 4 121 116 5
Gains on sales of other assets and
other, net - 32 (32 ) 10 32 (22 )
Operating income 231 223 8 444 442 2
Other income and expenses 21 34 (13 ) 41 55 (14 )
Noncontrolling interests 18 13 5 34 27 7
EBIT $ 234 $ 244 $ (10 ) $ 451 $ 470 $ (19 )
Proportional throughput, TBtu (a) 574 476 98 1,287 1,113 174
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(a) Trillion British thermal units. Revenues are not significantly affected by pipeline throughput fluctuations, since revenues are primarily composed of demand charges.
Three Months Ended June 30, 2009 Compared to Same Period in 2008
Operating Revenues. The $14 million increase was driven primarily by:
• a $40 million increase from expansion projects placed in service late in 2008 and in 2009,
• a $9 million increase in transportation and other revenues primarily from the acquisition of Ozark Gas Transmission, L.L.C. (Ozark Gas Transmission) in May 2009, and
• a $4 million increase in transportation and storage revenues from recoveries of fuel and electric power costs passed through to customers, partially offset by
• a $29 million decrease in processing revenues associated with pipeline operations, caused by lower prices and volumes, and
• a $5 million decrease resulting from a weaker Canadian dollar at M&N LP.
Operating, Maintenance and Other. The $30 million decrease was driven primarily by:
• a $34 million decrease in project development costs, reflecting a net benefit of $24 million in 2009 primarily due to a reimbursement of project development costs by customers on northeast expansions compared to expensed project development costs of $10 million in 2008, and
• a $7 million decrease in pipeline integrity costs, primarily due to the timing of pipeline integrity work, partially offset by
• a $5 million increase in operating costs primarily from higher fuel and electric power costs passed through to customers,
• a $4 million increase from expansion projects placed in service late in 2008 and in 2009, and
• a $4 million increase from Ozark Gas Transmission acquired in May 2009.
Depreciation and Amortization. The $4 million increase was primarily driven by expansion projects placed into service late in 2008 and in 2009.
Gains on Sales of Other Assets and Other, net. The $32 million decrease primarily reflects a customer bankruptcy settlement in June 2008.
Other Income and Expenses. The $13 million decrease was primarily a result of lower capitalization of interest on construction projects and from the discontinuance of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," accounting treatment by Southeast Supply Header, LLC (SESH), an equity investee. These decreases were partially offset by earnings from expansion projects on Gulfstream and SESH placed into service in late 2008.
Noncontrolling Interests. The $5 million increase was driven by an increase in the noncontrolling interests ownership percentage resulting from the Spectra Energy Partners public sale of additional partner units in the second quarter of 2009 and higher earnings from Spectra Energy Partners and M&N LLC.
EBIT. The $10 million decrease was primarily due to a customer bankruptcy settlement in the prior period, and lower processing revenues. These decreases were partially offset by higher earnings from expansion projects and lower project development costs.
Six Months Ended June 30, 2009 Compared to Same Period in 2008
Operating Revenues. The $16 million increase was driven primarily by:
• a $65 million increase from expansion projects placed in service late in 2008 and in 2009,
• a $12 million increase in transportation and storage revenues from recoveries of fuel and electric power costs passed through to customers, and
• a $9 million increase in transportation and other revenues primarily from Ozark Gas Transmission acquired in May 2009, partially offset by
• a $58 million decrease in processing revenues associated with pipeline operations, caused by lower prices and volumes, and
• a $12 million decrease resulting from a weaker Canadian dollar at M&N LP.
Operating, Maintenance and Other. The $13 million decrease was driven primarily by:
• a $34 million decrease in project development costs, reflecting a net benefit of $18 million in 2009 primarily due to a reimbursement of project development costs by customers on northeast expansions compared to expensed project development costs of $16 million in 2008, partially offset by
• a $12 million increase in operating costs primarily from higher fuel and electric power costs passed through to customers,
• an $8 million increase from expansion projects placed in service late in 2008 and in 2009, and
• a $4 million increase from Ozark Gas Transmission acquired in May 2009.
Depreciation and Amortization. The $5 million increase was primarily driven by expansion projects placed into service late in 2008 and in 2009.
Gains on Sales of Other Assets and Other, net. The $22 million decrease was primarily driven by a customer bankruptcy settlement of $31 million in June 2008, partially offset by a customer settlement of $10 million in 2009 resulting from the cancellation of a capital project.
Other Income and Expenses. The $14 million decrease was primarily a result of lower capitalization of interest on construction projects and from the discontinuance of SFAS No. 71 accounting treatment by SESH. These decreases were partially offset by earnings from expansion projects on Gulfstream and SESH placed into service in late 2008.
Noncontrolling Interests. The $7 million increase was driven by an increase in the noncontrolling interests ownership percentage resulting from the Spectra Energy Partners public sale of additional partner units in the second quarter of 2009 and higher earnings from Spectra Energy Partners and M&N LLC.
EBIT. The $19 million decrease was primarily due to lower processing revenues and a customer bankruptcy settlement in the prior period. These decreases were partially offset by higher earnings from expansion projects and lower project development costs.
Distribution
Three Months Six Months
Ended June 30, Ended June 30,
Increase Increase
2009 2008 (Decrease) 2009 2008 (Decrease)
(in millions, except where noted)
Operating revenues $ 284 $ 353 $ (69 ) $ 992 $ 1,153 $ (161 )
Operating expenses
Natural gas purchased 120 158 (38 ) 555 650 (95 )
Operating, maintenance and other 82 94 (12 ) 163 191 (28 )
Depreciation and amortization 42 46 (4 ) 82 93 (11 )
Operating income 40 55 (15 ) 192 219 (27 )
Other income and expenses - (1 ) 1 - - -
EBIT $ 40 $ 54 $ (14 ) $ 192 $ 219 $ (27 )
Number of customers, thousands 1,314 1,296 18
Heating degree days, Fahrenheit 918 899 19 4,616 4,550 66
Pipeline throughput, TBtu 129 151 (22 ) 456 479 (23 )
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Three Months Ended June 30, 2009 Compared to Same Period in 2008
Operating Revenues. The $69 million decrease was driven primarily by:
• a $47 million decrease resulting from a weaker Canadian dollar,
• a $32 million decrease from lower natural gas prices passed through to customers without a mark-up, and
• an $11 million decrease due to a settlement on 2008 earnings to be shared with customers, partially offset by
• a $15 million increase resulting from a charge in 2008 due to an unfavorable decision from the OEB related to unregulated storage revenues,
• a $9 million increase in storage and transportation revenues attributable to growth of the storage system and an increase in short-term transportation services provided to customers, and
• a $7 million increase due to growth in the number of customers.
Natural Gas Purchased. The $38 million decrease was driven primarily by:
• a $32 million decrease from lower natural gas prices passed through to customers without a mark-up, and
• a $21 million decrease resulting from a weaker Canadian dollar, partially offset by
• a $6 million increase due to growth in the number of customers, and
• a $6 million increase related to fuel used in operations.
Operating, Maintenance and Other. The $12 million decrease was driven primarily by a weaker Canadian dollar.
Depreciation and Amortization. The $4 million decrease was driven primarily by a weaker Canadian dollar.
EBIT. The $14 million decrease was primarily a result of the 2008 earnings sharing settlement reached in June 2009 and a weaker Canadian dollar. These decreases were partially offset by higher storage and transportation revenues.
Six Months Ended June 30, 2009 Compared to Same Period in 2008
Operating Revenues. The $161 million decrease was driven primarily by:
• a $214 million decrease resulting from a weaker Canadian dollar,
• a $28 million decrease in customer usage of natural gas due to conservation efforts and the impacts of the economic recession, and
• an $11 million decrease due to a settlement on 2008 earnings to be shared with customers, partially offset by
• a $31 million increase due to growth in the number of customers,
• a $28 million increase in storage and transportation revenues attributable to growth of the storage system and an increase in short-term transportation services provided to customers,
• a $27 million increase from higher natural gas prices passed through to customers without a mark-up, and
• a $15 million increase resulting from a charge in 2008 due to an unfavorable decision from the OEB related to unregulated storage revenues.
Natural Gas Purchased. The $95 million decrease was driven primarily by:
• a $123 million decrease resulting from a weaker Canadian dollar, and
• a $26 million decrease in customer usage of natural gas due to conservation efforts and the impacts of the economic recession, partially offset by
• a $27 million increase due to growth in the number of customers, and
• a $27 million increase from higher natural gas prices passed through to customers without a mark-up.
Operating, Maintenance and Other. The $28 million decrease was driven primarily by a weaker Canadian dollar.
Depreciation and Amortization. The $11 million decrease was driven primarily by a weaker Canadian dollar.
EBIT. The $27 million decrease was primarily a result of a weaker Canadian dollar, the 2008 earnings sharing settlement reached in June 2009 and lower customer usage of natural gas. These decreases were partially offset by higher storage and transportation revenues.
Western Canada Transmission & Processing
Three Months Six Months
Ended June 30, Ended June 30,
Increase Increase
2009 2008 (Decrease) 2009 2008 (Decrease)
(in millions, except where noted)
Operating revenues $ 239 $ 380 $ (141 ) $ 510 $ 777 $ (267 )
Operating expenses
Natural gas and petroleum products
purchased 34 118 (84 ) 105 248 (143 )
Operating, maintenance and other 108 128 (20 ) 196 232 (36 )
Depreciation and amortization 35 41 (6 ) 67 77 (10 )
Operating income 62 93 (31 ) 142 220 (78 )
Other income and expenses (4 ) (2 ) (2 ) (3 ) 1 (4 )
Noncontrolling interests - - - - 1 (1 )
EBIT $ 58 $ 91 $ (33 ) $ 139 $ 220 $ (81 )
Pipeline throughput, TBtu 136 142 (6 ) 298 304 (6 )
Volumes processed, TBtu 164 170 (6 ) 331 343 (12 )
Empress inlet volumes, TBtu 198 208 (10 ) 409 425 (16 )
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Three Months Ended June 30, 2009 Compared to Same Period in 2008
Operating Revenues. The $141 million decrease was driven primarily by:
• a $112 million decrease due to lower NGL product prices associated with the Empress operations, and
• a $37 million decrease as a result of a weaker Canadian dollar, partially offset by
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