SOUTHERN CALIFORNIA EDISON Co quarterly report, Q3 FY2012

Southern California Edison Company (SCE) — Form 10-Q Summary

Reporting period: Quarter and nine months ended September 30, 2012. SCE is a regulated California electric utility and a wholly owned subsidiary of Edison International. Dollar amounts are in millions unless stated otherwise.

Financial results and position

Metric	Q3 2012	Q3 2011	Nine months 2012	Nine months 2011
Operating revenue	$3,731	$3,386	$8,794	$8,063
Operating income	$659	$764	$1,487	$1,647
Net income	$388	$421	$802	$882
Net income available for common stock	$363	$406	$736	$838
Operating margin	17.7%	22.6%	16.9%	20.4%
Net margin	10.4%	12.4%	9.1%	10.9%

Margins are calculated as operating income or net income divided by operating revenue. Management reported no non-core earnings items; core earnings equaled net income available for common stock.

• Cash flow: Nine-month operating cash flow was $2,656, up from $2,272. Investing used $3,259, including $3,105 in capital expenditures; financing provided $636. Cash increased $33 to $90.
• Liquidity: At September 30, SCE had $90 in cash and $2,174 available under its $2.75 billion revolving credit facility, after $380 of commercial paper and $196 of letters of credit. The facility matures in May 2017.
• Debt and capital: Short- and long-term debt totaled $9,208, versus $8,850 at year-end 2011. SCE issued $400 of 4.05% mortgage bonds due 2042 and issued preference stock. Its credit-facility debt-to-capitalization covenant limit is 0.65; the reported ratio was 0.46.
• Balance sheet: Total assets were $43,059 and total equity was $11,064, compared with $40,315 and $9,958, respectively, at December 31, 2011. Regulatory assets totaled $6,338.

Material changes versus prior periods

• Common earnings fell $43 in Q3 and $102 for the first nine months. Management attributed the decline principally to the delayed 2012 general rate case (GRC), which left higher depreciation and net interest costs unrecovered under existing rates, and higher San Onofre costs.
• Revenue increased, in part because SCE began recognizing electricity sales previously supplied through California Department of Water Resources contracts that expired in 2011. Retail billed and unbilled revenue, excluding wholesale sales and balancing-account over- or undercollections, increased to $3.7 billion for Q3 and $8.7 billion year to date. Rate reductions and customer refunds partly offset the increase. SCE’s decoupling mechanism means retail sales changes do not directly determine earnings.
• Operating expenses increased faster than revenue. Nine-month purchased power and fuel expense rose $578, while depreciation, decommissioning and amortization rose $129 and operations and maintenance rose $172.
• Operating cash flow improved year over year, which SCE attributed largely to tax receipts and the timing of working-capital cash flows. Capital expenditures were $3.1 billion, versus $3.0 billion.

Outlook, management commentary, and significant risks

• San Onofre nuclear plant: Units 2 and 3 remained shut after steam-generator tube wear and leakage. SCE proposed restarting Unit 2 at 70% power for about five months, subject to NRC approval; there was no clear timetable or assurance of restart. Unit 3 would not restart in 2012, and its return to service and the cost of repairs or replacement remained uncertain.
• SCE reported $96 of incremental inspection and repair costs through September and $221 of replacement-power costs, net of avoided nuclear fuel costs. Replacement-power costs and specified other costs were subject to recovery and reasonableness review by the CPUC. The CPUC opened an investigation into San Onofre costs and could require rate reductions or refunds. SCE had recorded no recovery from the steam-generator supplier or insurance as of September 30; recovery was uncertain.
• GRC and rates: An October 19 proposed decision would set 2012 base-rate revenue at $5.69 billion, $601 below SCE’s request but about $400 above then-authorized revenue. The proposed decision was not final; a final decision was expected by year-end, and the adopted requirement would be effective retroactively from January 1, 2012. Proposed revenue requirements were $6.08 billion for 2013 and $6.43 billion for 2014.
• Capital plan: SCE expected 2012 capital spending to be below its previously projected $4.4–$5.0 billion range because of the delayed GRC decision, Tehachapi project delays, and San Onofre outages. It maintained a 2012–2014 capital expenditure outlook of $11.8–$13.2 billion. San Onofre reliability measures could add $100–$125 million of capital spending during 2013–2015 if approved.
• Cost of capital: SCE’s October update requested lower authorized costs: long-term debt 5.49%, preferred equity 5.79%, and common equity return 11.1%. Regulatory decisions remained pending.
• Other contingencies: The Malibu wildfire proceeding included proposed penalties of about $50 million for SCE; SCE disputed the allegations. A separate windstorm investigation could also result in penalties, which SCE could not estimate. Four Corners faced Clean Air Act litigation; a planned sale of SCE’s interest for an adjusted $279 million was subject to closing conditions and could terminate if not completed by December 31, 2012. Environmental remediation liabilities were $116 million, with possible additional costs estimated up to $191 million across identified sites.
• Other risk factors: Regulatory cost recovery and timing, nuclear safety and outage duration, power prices and availability, collateral needs, wildfire exposure and insurance limits, environmental requirements, and counterparty performance could affect cash flows or results. SCE stated that commodity-related gains and losses are generally offset through regulatory mechanisms, though timing may affect cash flows.
• Workforce action: SCE planned to reduce the San Onofre workforce by 730 employees, to 1,500, beginning in late 2012 and continuing into 2013; it had recorded $30 in estimated severance costs.

Most important facts for investors to verify

• Final CPUC GRC decision, including the revenue requirement, tax-repair treatment, and recovery of San Onofre costs.
• NRC decisions and actual restart timing, operating capacity, and repair needs for San Onofre Units 2 and 3.
• Whether replacement-power, repair, supplier, and insurance claims are recovered, and the effect of CPUC refund or rate-removal decisions.
• Actual capital spending, Tehachapi project schedule and cost, and any additional San Onofre reliability investment.
• Outcomes and potential financial exposure from the wildfire, windstorm, environmental, and Four Corners proceedings.