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| SE > SEC Filings for SE > Form 10-Q on 8-May-2009 | All Recent SEC Filings |
8-May-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 has been recast to reflect the reporting requirements of SFAS No. 160, which was adopted January 1, 2009. In addition, the Condensed Consolidated Statements of Operations and related information and discussions for the 2008 period have been recast to reflect the operating results of certain Western Canada Transmission & Processing natural gas gathering and processing facilities as discontinued operations. See Notes 5 and 18 of Notes to Condensed Consolidated Financial Statements for further discussion.
Executive Overview
For the three months ended March 31, 2009 and 2008, we reported net income from controlling interests of $298 million and $367 million, respectively. The decrease is due to lower earnings from Field Services and Western Canada Transmission & Processing as a result of lower NGL prices, which correlate to lower crude oil prices during the first three months of 2009. Crude oil averaged $43 per barrel for the three months ended March 31, 2009 versus $98 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 2009 associated with partnership units previously issued by DCP Partners.
The highlights for the three months ended March 31, 2009 include:
• U.S. Transmission's earnings decreased due primarily to lower margins from gas processing, partially offset by an increase from expansion projects placed into service in late 2008,
• Distribution results reflect a weaker Canadian dollar, 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
• results for Other decreased primarily due to an overall increase in the cost of benefits in 2009.
In the first quarter of 2009, we reported $176 million of capital and investment expenditures. Approximately $1 billion is projected for the full year and includes expansion capital of approximately $500 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 March 31, 2009, we continue to have ongoing access to approximately $2.6 billion in credit facilities and expect to continue to utilize commercial paper and revolving lines of credit, as needed, to fund liquidity needs throughout 2009.
As previously discussed, on May 4, 2009, Spectra Energy Partners acquired all of the ownership interests of NOARK from Atlas for approximately $295 million. See Note 19 of Notes to Condensed Consolidated Financial Statements for further discussion.
RESULTS OF OPERATIONS
Three Months
Ended March 31,
2009 2008
(in millions)
Operating revenues $ 1,384 $ 1,600
Operating expenses 969 1,107
Gains on sales of other assets and other, net 10 -
Operating income 425 493
Other income and expenses 176 220
Interest expense 150 158
Earnings from continuing operations before income taxes 451 555
Income tax expense from continuing operations 139 172
Income from continuing operations 312 383
Income from discontinued operations, net of tax 3 3
Net income 315 386
Net income-noncontrolling interests 17 19
Net income-controlling interests $ 298 $ 367
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Operating Revenues. The $216 million, or 14%, decrease was 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 natural gas prices passed through to customers without a mark-up, growth in the number of customers and higher storage and transportation revenues at Distribution.
Operating Expenses. The $138 million, or 12%, decrease was driven primarily by:
• the effects of a weaker Canadian dollar at Western Canada Transmission & Processing and Distribution, and
• lower prices of natural gas purchased for the Empress facility, partially offset by
• higher natural gas prices passed through to customers without a mark-up and growth in the number of customers at Distribution.
Operating Income. The $68 million, or 14%, decrease was driven primarily by lower NGL product prices associated with the Empress operations at Western Canada Transmission & Processing and a weaker Canadian dollar, partially offset by higher storage and transportation revenues at Distribution.
Other Income and Expenses. The $44 million decrease was attributable to lower equity in earnings from Field Services, reflecting primarily lower commodity prices, partially offset by a gain associated with partnership units previously issued by DCP Partners.
Income Tax Expense from Continuing Operations. The $33 million decrease relates primarily to lower earnings in the first quarter of 2009. The effective tax rate was 30.8% in the first quarter of 2009 compared with 31.0% in the first quarter of 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
Ended March 31,
2009 2008
(in millions)
U.S. Transmission $ 217 $ 226
Distribution 152 165
Western Canada Transmission & Processing 81 129
Field Services 150 192
Total reportable segment EBIT 600 712
Other (24 ) (20 )
Total reportable segment and other EBIT 576 692
Interest expense (150 ) (158 )
Interest income and other (a) 25 21
Earnings from continuing operations before income taxes $ 451 $ 555
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(a) Other 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
Ended March 31,
Increase
2009 2008 (Decrease)
(in millions, except where noted)
Operating revenues $ 405 $ 403 $ 2
Operating expenses
Operating, maintenance and other 143 126 17
Depreciation and amortization 59 58 1
Gains on sales of other assets and other, net 10 - 10
Operating income 213 219 (6 )
Other income and expenses 20 21 (1 )
Noncontrolling interests 16 14 2
EBIT $ 217 $ 226 $ (9 )
Proportional throughput, TBtu (a) 713 636 77
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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.
Operating Revenues. The $2 million increase was driven primarily by:
• a $25 million increase from expansion projects placed in service in late 2008, and
• a $15 million increase in transportation and storage revenues due to increased firm storage contracts and recoveries of fuel and electric power costs through transportation revenues, partially offset by
• a $29 million decrease in processing revenues associated with pipeline operations, caused by both lower prices and volumes, and
• a $7 million decrease resulting from a weaker Canadian dollar, related to M&N LP.
Operating, Maintenance and Other. The $17 million increase was driven primarily by:
• a $12 million increase in operating costs including fuel, utilities and software costs, and
• a $5 million increase in ad valorem taxes, primarily as a result of business expansion projects and capital assets placed in service in late 2008.
Gains on Sales of Other Assets, net. The $10 million recognized in 2009 reflects a customer settlement resulting from the cancellation of a capital project.
EBIT. The $9 million decrease reflects a decrease in processing revenues, partially offset by higher earnings from expansion projects.
Distribution
Three Months
Ended March 31,
Increase
2009 2008 (Decrease)
(in millions, except where noted)
Operating revenues $ 708 $ 800 $ (92 )
Operating expenses
Natural gas purchased 435 492 (57 )
Operating, maintenance and other 81 97 (16 )
Depreciation and amortization 40 47 (7 )
Operating income 152 164 (12 )
Other income and expenses - 1 (1 )
EBIT $ 152 $ 165 $ (13 )
Number of customers, thousands 1,312 1,293 19
Heating degree days, Fahrenheit 3,698 3,651 47
Pipeline throughput, TBtu 327 327 -
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Operating Revenues. The $92 million decrease was driven primarily by:
• a $167 million decrease resulting from a weaker Canadian dollar, and
• a $33 million decrease in customer usage of natural gas, partially offset by
• a $59 million increase from higher natural gas prices passed through to customers without a mark-up,
• a $24 million increase due to growth in the number of customers, and
• a $23 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.
Natural Gas Purchased. The $57 million decrease was driven primarily by:
• a $102 million decrease resulting from a weaker Canadian dollar, and
• a $34 million decrease in customer usage of natural gas, partially offset by
• a $59 million increase from higher natural gas prices passed through to customers without a mark-up, and
• a $21 million increase due to growth in the number of customers.
Operating, Maintenance and Other. The $16 million decrease was driven primarily by a weaker Canadian dollar.
Depreciation and Amortization. The $7 million decrease was driven primarily by a weaker Canadian dollar.
EBIT. The $13 million decrease was primarily attributable to a weaker Canadian dollar, partially offset by higher storage and transportation revenues during the period.
Western Canada Transmission & Processing
Three Months
Ended March 31,
Increase
2009 2008 (Decrease)
(in millions, except where noted)
Operating revenues $ 271 $ 397 $ (126 )
Operating expenses
Natural gas and petroleum products purchased 71 130 (59 )
Operating, maintenance and other 88 104 (16 )
Depreciation and amortization 32 36 (4 )
Operating income 80 127 (47 )
Other income and expenses 1 3 (2 )
Noncontrolling interests - 1 (1 )
EBIT $ 81 $ 129 $ (48 )
Pipeline throughput, TBtu 162 162 -
Volumes processed, TBtu 167 173 (6 )
Empress inlet volumes, TBtu 211 217 (6 )
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Operating Revenues. The $126 million decrease was driven primarily by:
• an $83 million decrease due to lower NGL product prices associated with the Empress operations, and
• a $64 million decrease as a result of a weaker Canadian dollar, partially offset by
• a $12 million increase resulting primarily from higher gathering and processing revenues due to higher firm volumes.
Natural Gas and Petroleum Products Purchased. The $59 million decrease was driven primarily by:
• a $43 million decrease arising from lower prices of natural gas purchased for the Empress facility, and
• a $16 million decrease caused by a weaker Canadian dollar.
Operating, Maintenance and Other. The $16 million decrease was driven primarily by:
• a $26 million decrease caused by a weaker Canadian dollar, partially offset by
• an $8 million increase in costs relating mainly to carbon taxes.
Depreciation and Amortization. The $4 million decrease was driven primarily by a weaker Canadian dollar.
EBIT. The $48 million decrease was driven primarily by lower NGL product prices that negatively impacted the Empress operations, as well as a weaker Canadian dollar.
Field Services
Three Months
Ended March 31,
Increase
2009 2008 (Decrease)
(in millions, except where noted)
Operating expenses $ - $ (1 ) $ 1
Operating income - 1 (1 )
Equity in earnings of unconsolidated
affiliates 150 191 (41 )
EBIT $ 150 $ 192 $ (42 )
Natural gas gathered and
processed/transported, TBtu/d (a,b) 7.0 7.2 (0.2 )
NGL production, MBbl/d (a,c) 331 380 (49 )
Average natural gas price per MMBtu (d) $ 4.89 $ 8.03 $ (3.14 )
Average NGL price per gallon (e) $ 0.57 $ 1.34 $ (0.77 )
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(a) Reflects 100% of volumes.
(b) Trillion British thermal units per day.
(c) Thousand barrels per day.
(d) Million British thermal units. Average price based on NYMEX Henry Hub.
(e) Does not reflect results of commodity hedges.
EBIT. Lower equity earnings of $41 million were primarily the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
• a $173 million decrease from commodity-sensitive processing arrangements, due to decreased commodity prices,
• a $22 million decrease in gathering and processing margins primarily attributable to lower volumes associated with plant outages, and lower recoveries and efficiencies, and
• an $8 million decrease due to higher net interest expense resulting from the increased debt associated with growth and acquisitions in 2008, partially offset by
• a $135 million gain associated with partnership units previously issued by DCP Partners,
• an $18 million increase in marketing margins related to higher NGL trading results and derivatives timing,
• a $6 million increase in earnings from DCP Partners primarily as a result of mark-to-market gains on hedges used to protect distributable cash flows, and
• a $3 million increase primarily as a result of lower operating and maintenance expenses due to cost reduction initiatives, partially offset by higher depreciation expense as a result of capital spending and acquisitions in 2008.
Other
Three Months
Ended March 31,
Increase
2009 2008 (Decrease)
(in millions)
Operating revenues $ 12 $ 9 $ 3
Operating expenses 32 28 4
Operating loss (20 ) (19 ) (1 )
Other income and expenses (4 ) (1 ) (3 )
EBIT $ (24 ) $ (20 ) $ (4 )
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EBIT. The $4 million increase in net costs reflects an overall increase in the cost of employee benefits in 2009.
LIQUIDITY AND CAPITAL RESOURCES
Net working capital was negative $1,135 million as of March 31, 2009, which included short-term borrowings and commercial paper totaling $405 million and current maturities of long-term debt of $792 million. We will rely primarily upon cash flows from operations and additional financing transactions to fund our liquidity and capital requirements for the next 12 months including issuances of short-term and long-term debt. See Financing Cash Flows and Liquidity for discussions of effective shelf registrations and available credit facilities.
Operating Cash Flows
Net cash provided by operating activities decreased $117 million to $556 million for the three months ended March 31, 2009 compared to the same period in 2008, driven mainly by a $107 million decrease in distributions received from unconsolidated affiliates in 2009, primarily from DCP Midstream, and lower earnings.
Investing Cash Flows
Cash flows used in investing activities decreased $230 million to $142 million in the first three months of 2009 compared to the same period in 2008. This change was driven primarily by a $199 million decrease in capital and investment expenditures in 2009 as a result of projects that were placed into service in 2008 and early 2009 and planned reduced capital expansion levels for 2009 compared to 2008.
Three Months
Ended March 31,
2009 2008
(in millions)
Capital and Investment Expenditures
U.S. Transmission $ 99 $ 272
Distribution 34 63
Western Canada Transmission & Processing 37 32
Other 6 8
Total $ 176 $ 375
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Capital and investment expenditures for the three months ended March 31, 2009 consisted of $119 million for expansion projects and $57 million for maintenance and other projects.
As previously discussed, on May 4, 2009, Spectra Energy Partners acquired all of the ownership interests of NOARK from Atlas for approximately $295 million. See Note 19 of Notes to Condensed Consolidated Financial Statements for further discussion.
We continue to project 2009 capital and investment expenditures of approximately $1.0 billion, excluding the acquisition of NOARK, consisting of approximately $400 million for U.S. Transmission, $200 million for Distribution and $400 million for Western Canada Transmission & Processing. Total projected 2009 capital and investment expenditures include approximately $500 million of expansion capital expenditures and $500 million for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. We will continue to assess short and long-term market requirements and will adjust our capital plans as required. We anticipate placing approximately $650 million of capital expansion projects into service in 2009.
Financing Cash Flows and Liquidity
Our consolidated capital structure includes long-term debt, short-term borrowings, commercial paper and preferred stock of subsidiaries. As of March 31, 2009, our capital structure was 58% debt, 38% common equity of controlling interests and 4% noncontrolling interests and preferred stock of subsidiaries.
Net cash used in financing activities totaled $405 million in the first three months of 2009 compared to $139 million in the first three months of 2008. This change was driven primarily by:
• $530 million decrease in short-term borrowings in 2009 compared to a $42 million increase in the 2008 period, and
• $159 million net payments of long-term debt in 2009 compared to $31 million in 2008, partially offset by
• proceeds of $448 million in 2009 from the issuance of common stock.
As previously discussed, 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. We used the net proceeds to repay commercial paper as it matured. Borrowings from the commercial paper were used primarily for capital expenditures and for other general corporate purposes.
Available Credit Facilities and Restrictive Debt Covenants. See Note 10 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and related financial and other covenants.
The terms of our Spectra Capital credit agreement requires our consolidated debt-to-total-capitalization ratio to be 65% or lower. As of March 31, 2009, this ratio was 58%. Our equity and, as a result, this ratio, are sensitive to . . .
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