SOUTHERN CALIFORNIA EDISON Co quarterly report, Q3 FY2011

Southern California Edison Company — Form 10-Q Summary

Reporting period: Quarter and nine months ended September 30, 2011. SCE is a regulated electric utility serving Southern California and a wholly owned subsidiary of Edison International. Unless stated otherwise, amounts are in millions of dollars.

Financial performance

Metric	Q3 2011	Q3 2010	Nine months 2011	Nine months 2010
Operating revenue	$3,386	$3,098	$8,063	$7,504
Operating income	$764	$696	$1,647	$1,481
Net income	$421	$407	$882	$897
Net income available for common stock	$406	$394	$838	$858
Operating margin	22.6%	22.5%	20.4%	19.7%

• Quarterly common earnings rose $12 million; nine-month common earnings fell $20 million. Management’s non-GAAP core earnings were $406 million and $838 million in 2011, up $54 million and $36 million, respectively, from the comparable periods.
• Revenue increased 9.3% for the quarter and 7.5% year to date. Management attributed growth primarily to authorized rate increases, transmission-related revenue and capital-related revenue requirements. Operating income rose 9.8% and 11.2%, respectively.
• Quarterly purchased-power expense increased $146 million, principally because SCE replaced expired California Department of Water Resources (CDWR) contracts. Year-to-date purchased-power expense rose $85 million; higher renewable-contract prices were partly offset by fewer outage-related purchases than in 2010. Higher energy-efficiency costs also increased operating and maintenance expense.
• Nine-month income tax expense was $496 million versus $338 million, and the effective tax rate was 36% versus 27%. The 2010 comparison benefited from a $95 million tax settlement benefit and a $40 million tax-accounting benefit, partly offset by a $39 million health-care-legislation charge.

Cash flow, debt and liquidity

• Nine-month operating cash flow was $2.272 billion, down from $2.656 billion. Investing used $3.136 billion, including $3.014 billion of cash capital expenditures, compared with $2.883 billion used and $2.659 billion of capital expenditures in 2010. Financing provided $672 million; cash declined $192 million to $65 million.
• At September 30, 2011, short-term debt was $550 million and long-term debt was $8.032 billion, versus no short-term debt and $7.627 billion of long-term debt at year-end 2010. SCE issued $500 million of 3.875% bonds due 2021 and $125 million of 6.5% preference stock during the period.
• Available liquidity was $2.261 billion: $2.894 billion in credit facilities less $550 million of borrowings and $83 million of letters of credit. The debt-to-capitalization ratio was 0.47 against a 0.65 covenant limit. The 13-month weighted-average common-equity component was 50.5%, above the 48% dividend threshold; reported additional dividend capacity was $436 million.
• SCE paid $345 million in dividends to its parent during the first nine months. Its commodity derivatives had a net liability fair value of $641 million, up from $207 million at year-end; regulatory mechanisms generally defer the earnings effect, though cash flows and collateral needs can be affected.

Changes, outlook and management commentary

• Management maintained its 2011 capital-expenditure forecast of $3.9–$4.4 billion and projected $15.6–$17.5 billion for 2011–2014. Nine-month capital investment was reported as $2.5 billion, including accruals, versus $2.4 billion in 2010; the cash-flow capital-expenditure measure is reported separately above.
• SCE’s updated 2012 general rate case request was a $6.3 billion base revenue requirement, with proposed incremental customer base-rate increases of $824 million in 2012, $136 million in 2013 and $532 million in 2014. Ratepayer advocates proposed substantial reductions, and SCE could not predict the CPUC’s final decision. A memorandum account was authorized to make the eventual approved requirement effective from January 1, 2012 if the decision is delayed.
• FERC accepted SCE’s proposed transmission formula-rate framework subject to refund and settlement procedures, but reduced the proposed base return on equity from 11.5% to 9.93%. SCE estimated a 2012 weighted-average FERC return of 11.1% and reduced its forecast 2012 transmission revenue requirement by $49 million to $722 million. Final rate terms remained uncertain.
• SCE expected approximately $25 million of fourth-quarter 2011 revenue after the CPUC authorized recovery of certain legal costs. CDWR contracts allocated to SCE were expected to end by year-end 2011; replacement contracts were expected to increase both revenue and purchased-power expense. The customer-rate effects of continuing CDWR reserve refunds were expected to extend into 2012.
• Potential cost and operating impacts include proposed once-through-cooling requirements, California’s 33% renewable-procurement law, possible nuclear-safety requirements following events in Japan, and engineering, permitting and cost pressures on the Tehachapi transmission project. SCE said potential entrainment-compliance costs at San Onofre could be significant but could not yet be assessed.

Risks, contingencies and unusual items

• In the Malibu wildfire investigation, CPUC staff proposed approximately $99 million in penalties for respondents, allocating about $50 million to SCE. SCE disputed the allegations and said it could not predict any penalty ultimately imposed.
• A new Four Corners Clean Air Act lawsuit seeks injunctive relief, penalties and other remedies. SCE could not predict the outcome or estimate the financial impact. Its planned sale of its ownership interest remained subject to approvals and was expected to close in late 2012.
• Recorded environmental-remediation liabilities were $51 million for 24 material sites and $3 million for 33 immaterial sites. SCE said reasonably possible costs could exceed recorded amounts by up to $195 million and $7 million, respectively; it expects substantial recovery through customer rates.
• An IRS proposed adjustment to a repair deduction, if sustained, could require approximately $92 million of federal tax payment including interest through September 30, 2011. SCE disputed the adjustment and had filed a protest.
• SCE’s nuclear liabilities include potential industry assessments: up to approximately $235 million per nuclear incident, limited to about $35 million in any one year, and retrospective property-insurance premiums of up to about $48 million annually if covered losses exceed accumulated funds. These are contingent exposures, not stated current liabilities.
• The Navajo Nation litigation was settled and dismissed in August 2011, with no material financial-statement impact. Separately, a federal court had awarded SCE and co-owners approximately $142 million for DOE spent-fuel delays through 2005; recovery of later costs would require further legal action, and ratepayer treatment is subject to CPUC review.

Investor facts to verify

• Track the final CPUC general rate case decision against SCE’s request and intervenor reductions, and assess the resulting rates and earnings recovery.
• Monitor FERC formula-rate settlement or final order, authorized returns, and the potential effect on transmission revenue.
• Verify delivery of the capital program, especially Tehachapi costs, project timing and future rate recovery.
• Follow the Malibu penalty proceeding, Four Corners litigation and environmental-rulemaking developments for changes in exposure or required spending.
• Monitor operating cash generation, borrowing and collateral needs, and the timing and recoverability of regulatory assets and costs.