SOUTHERN CALIFORNIA EDISON Co - Quarter Report: 2012 June (Form 10-Q)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________
FORM 10-Q
________________________
(Mark One) | |
R | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2012 | |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to | |
Commission File Number 1-2313
________________________
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
________________________
California (State or other jurisdiction of incorporation or organization) | 95-1240335 (I.R.S. Employer Identification No.) | |
2244 Walnut Grove Avenue (P.O. Box 800) Rosemead, California (Address of principal executive offices) | 91770 (Zip Code) | |
(626) 302-1212 (Registrant's telephone number, including area code) | ||
________________________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes S No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes S No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer o | Non-accelerated filer x (Do not check if a smaller reporting company) | Smaller reporting company o | |||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No S
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Class | Outstanding at July 27, 2012 | |
Common Stock, no par value | 434,888,104 | |
TABLE OF CONTENTS
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GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
2011 Form 10-K | SCE's Annual Report on Form 10-K for the year-ended December 31, 2011 | |
2010 Tax Relief Act | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 | |
AFUDC | allowance for funds used during construction | |
APS | Arizona Public Service Company | |
ARO(s) | asset retirement obligation(s) | |
Bcf | billion cubic feet | |
Big 4 | Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects | |
CAA | Clean Air Act | |
CAIR | Clean Air Interstate Rule | |
CAISO | California Independent System Operator | |
CAMR | Clean Air Mercury Rule | |
CARB | California Air Resources Board | |
CDWR | California Department of Water Resources | |
CEC | California Energy Commission | |
CPUC | California Public Utilities Commission | |
CRRs | congestion revenue rights | |
DOE | U. S. Department of Energy | |
ERRA | energy resource recovery account | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
FGIC | Financial Guarantee Insurance Company | |
FIP(s) | federal implementation plan(s) | |
Four Corners | coal fueled electric generating facility located in Farmington, New Mexico in which SCE holds a 48% ownership interest | |
GAAP | generally accepted accounting principles | |
GHG | greenhouse gas | |
Global Settlement | A settlement between Edison International and the IRS that resolves all of SCE's federal income tax disputes and affirmative claims for tax years 1986 through 2002 and related matters with state tax authorities. | |
GRC | general rate case | |
IRS | Internal Revenue Service | |
ISO | Independent System Operator | |
kWh(s) | kilowatt-hour(s) | |
MD&A | Management's Discussion and Analysis of Financial Condition and Results of Operations in this report | |
Mohave | two coal fueled electric generating facilities that no longer operate located in Clark County, Nevada in which SCE holds a 56% ownership interest | |
Moody's | Moody's Investors Service | |
MRTU | Market Redesign Technology Upgrade | |
MW | megawatts | |
MWh | megawatt-hours | |
NAAQS | national ambient air quality standards | |
NERC | North American Electric Reliability Corporation | |
Ninth Circuit | U.S. Court of Appeals for the Ninth Circuit | |
NOx | nitrogen oxide | |
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NRC | Nuclear Regulatory Commission | |
NSR | New Source Review | |
Palo Verde | large pressurized water nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest | |
PBOP(s) | postretirement benefits other than pension(s) | |
PBR | performance-based ratemaking | |
PG&E | Pacific Gas & Electric Company | |
PSD | Prevention of Significant Deterioration | |
QF(s) | qualifying facility(ies) | |
ROE | return on equity | |
S&P | Standard & Poor's Ratings Services | |
San Onofre | large pressurized water nuclear electric generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest | |
SCAQMD | South Coast Air Quality Management District | |
SCE | Southern California Edison Company | |
SDG&E | San Diego Gas & Electric | |
SEC | U.S. Securities and Exchange Commission | |
SIP(s) | state implementation plan(s) | |
SO2 | sulfur dioxide | |
SRP | Salt River Project Agricultural Improvement and Power District | |
US EPA | U.S. Environmental Protection Agency | |
VIE(s) | variable interest entity(ies) | |
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Statements of Income | Southern California Edison Company |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in millions, unaudited) | 2012 | 2011 | 2012 | 2011 | ||||||||||||
Operating revenue | $ | 2,651 | $ | 2,446 | $ | 5,063 | $ | 4,678 | ||||||||
Fuel | 61 | 83 | 138 | 159 | ||||||||||||
Purchased power | 822 | 649 | 1,437 | 1,158 | ||||||||||||
Operation and maintenance | 866 | 846 | 1,717 | 1,631 | ||||||||||||
Depreciation, decommissioning and amortization | 399 | 356 | 788 | 700 | ||||||||||||
Property and other taxes | 73 | 69 | 156 | 146 | ||||||||||||
Total operating expenses | 2,221 | 2,003 | 4,236 | 3,794 | ||||||||||||
Operating income | 430 | 443 | 827 | 884 | ||||||||||||
Interest income | 2 | 2 | 3 | 5 | ||||||||||||
Other income | 36 | 39 | 67 | 77 | ||||||||||||
Interest expense | (127 | ) | (117 | ) | (249 | ) | (228 | ) | ||||||||
Other expenses | (19 | ) | (13 | ) | (26 | ) | (25 | ) | ||||||||
Income before income taxes | 322 | 354 | 622 | 713 | ||||||||||||
Income tax expense | 108 | 128 | 208 | 251 | ||||||||||||
Net income | 214 | 226 | 414 | 462 | ||||||||||||
Less: Dividends on preferred and preference stock | 23 | 15 | 41 | 29 | ||||||||||||
Net income available for common stock | $ | 191 | $ | 211 | $ | 373 | $ | 433 | ||||||||
Consolidated Statements of Comprehensive Income | ||||||||||||||||
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in millions, unaudited) | 2012 | 2011 | 2012 | 2011 | ||||||||||||
Net income | $ | 214 | $ | 226 | $ | 414 | $ | 462 | ||||||||
Other comprehensive income, net of tax: | ||||||||||||||||
Pension and postretirement benefits other than pensions: | ||||||||||||||||
Net loss arising during the period, net of income tax benefit of $3 for both the three- and six-month periods ended June 30, 2012. | (4 | ) | — | (4 | ) | — | ||||||||||
Amortization of net loss included in net income, net of income tax expense of $1 and $1 for three months ended June 30, 2012 and 2011, respectively and $3 and $1 for the six months ended June 30, 2012 and 2011, respectively. | 1 | 1 | 4 | 2 | ||||||||||||
Comprehensive income | $ | 211 | $ | 227 | $ | 414 | $ | 464 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Consolidated Balance Sheets | Southern California Edison Company |
(in millions, unaudited) | June 30, 2012 | December 31, 2011 | ||||||
ASSETS | ||||||||
Cash and cash equivalents | $ | 41 | $ | 57 | ||||
Receivables, less allowances of $74 and $75 for uncollectible accounts at respective dates | 721 | 760 | ||||||
Accrued unbilled revenue | 726 | 519 | ||||||
Inventory | 335 | 350 | ||||||
Prepaid taxes | 275 | 278 | ||||||
Derivative assets | 45 | 65 | ||||||
Regulatory assets | 586 | 494 | ||||||
Other current assets | 234 | 89 | ||||||
Total current assets | 2,963 | 2,612 | ||||||
Nuclear decommissioning trusts | 3,810 | 3,592 | ||||||
Other investments | 110 | 93 | ||||||
Total investments | 3,920 | 3,685 | ||||||
Utility property, plant and equipment, less accumulated depreciation of $7,153 and $6,894 at respective dates | 28,708 | 27,569 | ||||||
Nonutility property, plant and equipment, less accumulated depreciation of $113 and $107 at respective dates | 70 | 73 | ||||||
Total property, plant and equipment | 28,778 | 27,642 | ||||||
Derivative assets | 59 | 70 | ||||||
Regulatory assets | 5,776 | 5,815 | ||||||
Other long-term assets | 507 | 491 | ||||||
Total long-term assets | 6,342 | 6,376 | ||||||
Total assets | $ | 42,003 | $ | 40,315 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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Consolidated Balance Sheets | Southern California Edison Company |
(in millions, except share amounts, unaudited) | June 30, 2012 | December 31, 2011 | ||||||
LIABILITIES AND EQUITY | ||||||||
Short-term debt | $ | 300 | $ | 419 | ||||
Accounts payable | 1,070 | 1,319 | ||||||
Accrued taxes | 35 | 49 | ||||||
Accrued interest | 192 | 167 | ||||||
Customer deposits | 195 | 199 | ||||||
Derivative liabilities | 173 | 266 | ||||||
Regulatory liabilities | 721 | 670 | ||||||
Other current liabilities | 589 | 759 | ||||||
Total current liabilities | 3,275 | 3,848 | ||||||
Long-term debt | 8,827 | 8,431 | ||||||
Deferred income taxes | 6,339 | 5,781 | ||||||
Deferred investment tax credits | 81 | 84 | ||||||
Customer advances | 150 | 138 | ||||||
Derivative liabilities | 796 | 805 | ||||||
Pensions and benefits | 2,333 | 2,461 | ||||||
Asset retirement obligations | 2,691 | 2,610 | ||||||
Regulatory liabilities | 5,038 | 4,670 | ||||||
Other deferred credits and other long-term liabilities | 1,657 | 1,529 | ||||||
Total deferred credits and other liabilities | 19,085 | 18,078 | ||||||
Total liabilities | 31,187 | 30,357 | ||||||
Commitments and contingencies (Note 9) | ||||||||
Common stock, no par value (560,000,000 shares authorized; 434,888,104 shares issued and outstanding at each date) | 2,168 | 2,168 | ||||||
Additional paid-in capital | 595 | 596 | ||||||
Accumulated other comprehensive loss | (24 | ) | (24 | ) | ||||
Retained earnings | 6,282 | 6,173 | ||||||
Total common shareholder's equity | 9,021 | 8,913 | ||||||
Preferred and preference stock | 1,795 | 1,045 | ||||||
Total equity | 10,816 | 9,958 | ||||||
Total liabilities and equity | $ | 42,003 | $ | 40,315 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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Consolidated Statements of Cash Flows | Southern California Edison Company |
Six months ended June 30, | ||||||||
(in millions, unaudited) | 2012 | 2011 | ||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 414 | $ | 462 | ||||
Adjustments to reconcile to net cash provided by operating activities: | ||||||||
Depreciation, decommissioning and amortization | 788 | 700 | ||||||
Regulatory impacts of net nuclear decommissioning trust earnings | 114 | 75 | ||||||
Other amortization | 37 | 62 | ||||||
Stock-based compensation | 8 | 8 | ||||||
Deferred income taxes and investment tax credits | 250 | 436 | ||||||
Proceeds from U.S. treasury grants | 29 | — | ||||||
Changes in operating assets and liabilities: | ||||||||
Receivables | 11 | 61 | ||||||
Inventory | 15 | 1 | ||||||
Margin and collateral deposits – net of collateral received | (3 | ) | (8 | ) | ||||
Prepaid taxes | 3 | 107 | ||||||
Other current assets | (203 | ) | (167 | ) | ||||
Accounts payable | 28 | 15 | ||||||
Accrued taxes | (14 | ) | (18 | ) | ||||
Other current liabilities | (79 | ) | (191 | ) | ||||
Derivative assets and liabilities – net | (72 | ) | 326 | |||||
Regulatory assets and liabilities – net | 245 | (260 | ) | |||||
Other assets | (21 | ) | (191 | ) | ||||
Other liabilities | (39 | ) | (33 | ) | ||||
Net cash provided by operating activities | 1,511 | 1,385 | ||||||
Cash flows from financing activities: | ||||||||
Long-term debt issued | 395 | 497 | ||||||
Long-term debt issuance costs | (4 | ) | (5 | ) | ||||
Long-term debt repaid | (3 | ) | (3 | ) | ||||
Bonds purchased | — | (56 | ) | |||||
Preference stock issued – net | 805 | 123 | ||||||
Preference stock redeemed | (75 | ) | — | |||||
Short-term debt financing – net | (125 | ) | 200 | |||||
Settlements of stock-based compensation – net | (20 | ) | (7 | ) | ||||
Dividends paid | (261 | ) | (258 | ) | ||||
Net cash provided by financing activities | 712 | 491 | ||||||
Cash flows from investing activities: | ||||||||
Capital expenditures | (2,125 | ) | (2,019 | ) | ||||
Proceeds from sale of nuclear decommissioning trust investments | 1,097 | 1,146 | ||||||
Purchases of nuclear decommissioning trust investments and other | (1,222 | ) | (1,230 | ) | ||||
Customer advances for construction and other investments | 11 | 12 | ||||||
Net cash used by investing activities | (2,239 | ) | (2,091 | ) | ||||
Net decrease in cash and cash equivalents | (16 | ) | (215 | ) | ||||
Cash and cash equivalents, beginning of period | 57 | 257 | ||||||
Cash and cash equivalents, end of period | $ | 41 | $ | 42 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1. Summary of Significant Accounting Policies
SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to an approximately 50,000 square-mile area of southern California. SCE is a wholly-owned subsidiary of Edison International.
Basis of Presentation
SCE's significant accounting policies were described in Note 1 of "SCE Notes to Consolidated Financial Statements" included in the 2011 Form 10-K. The same accounting policies are followed for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2012, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2011 Form 10-K.
In the opinion of management, all adjustments, consisting of recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 2012 are not necessarily indicative of the operating results for the full year.
The December 31, 2011 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.
Cash Equivalents
Cash equivalents included investments in money market funds totaling $5 million and $21 million at June 30, 2012 and December 31, 2011, respectively. Generally, the carrying value of cash equivalents equals the fair value, as these investments have original maturities of three months or less.
SCE temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. SCE reclassified $130 million and $220 million of checks issued, but not yet paid by the financial institution, from cash to accounts payable at June 30, 2012 and December 31, 2011, respectively.
Inventory
Inventory is stated at the lower of cost or market, cost being determined by the average cost method for fuel and materials and supplies. Inventory consisted of the following:
(in millions) | June 30, 2012 | December 31, 2011 | |||||
Fuel | $ | 19 | $ | 24 | |||
Materials and supplies, spare parts | 316 | 326 | |||||
Total inventory | $ | 335 | $ | 350 | |||
Revenue Recognition
Operating revenue is recognized when electricity is delivered and includes amounts for services rendered but unbilled at the end of each reporting period. During the first six months of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement included in customer rates. A GRC memorandum account has been established for SCE, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.
New Accounting Guidance
Accounting Guidance Adopted in 2012
Fair Value Measurement
In May 2011, the Financial Accounting Standards Board ("FASB") issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new
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disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. SCE adopted this guidance effective January 1, 2012. For further information, see Note 4.
Presentation of Comprehensive Income
In June 2011 and December 2011, the FASB issued accounting standards updates on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. SCE adopted this guidance January 1, 2012 and elected to present two separate but consecutive statements. The adoption of these accounting standards updates did not change the items that constitute net income and other comprehensive income.
Accounting Guidance Not Yet Adopted
Offsetting Assets and Liabilities
In December 2011, the FASB issued an accounting standards update modifying the disclosure requirements about the nature of an entity's rights of offsetting assets and liabilities in the statement of financial position under master netting agreements and related arrangements associated with financial and derivative instruments. The guidance requires increased disclosure of the gross and net recognized assets and liabilities, collateral positions and narrative descriptions of setoff rights. SCE will adopt this guidance effective January 1, 2013.
Note 2. Consolidated Statements of Changes in Equity
The following table provides the changes in equity for the six months ended June 30, 2012.
Equity Attributable to SCE | |||||||||||||||||||||||
(in millions) | Common Stock | Additional Paid-in Capital | Accumulated Other Comprehensive Loss | Retained Earnings | Preferred and Preference Stock | Total Equity | |||||||||||||||||
Balance at December 31, 2011 | $ | 2,168 | $ | 596 | $ | (24 | ) | $ | 6,173 | $ | 1,045 | $ | 9,958 | ||||||||||
Net income | — | — | — | 414 | — | 414 | |||||||||||||||||
Other comprehensive income | — | — | — | — | — | — | |||||||||||||||||
Dividends declared on common stock | — | — | — | (233 | ) | — | (233 | ) | |||||||||||||||
Dividends declared on preferred and preference stock | — | — | — | (41 | ) | — | (41 | ) | |||||||||||||||
Stock-based compensation and other | — | 10 | — | (30 | ) | — | (20 | ) | |||||||||||||||
Noncash stock-based compensation and other | — | 8 | — | — | — | 8 | |||||||||||||||||
Issuance of preference stock | — | (20 | ) | — | — | 825 | 805 | ||||||||||||||||
Redemption of preference stock | — | 1 | — | (1 | ) | (75 | ) | (75 | ) | ||||||||||||||
Balance at June 30, 2012 | $ | 2,168 | $ | 595 | $ | (24 | ) | $ | 6,282 | $ | 1,795 | $ | 10,816 | ||||||||||
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The following table provides the changes in equity for the six months ended June 30, 2011.
Equity Attributable to SCE | |||||||||||||||||||||||
(in millions) | Common Stock | Additional Paid-in Capital | Accumulated Other Comprehensive Loss | Retained Earnings | Preferred and Preference Stock | Total Equity | |||||||||||||||||
Balance at December 31, 2010 | $ | 2,168 | $ | 572 | $ | (25 | ) | $ | 5,572 | $ | 920 | $ | 9,207 | ||||||||||
Net income | — | — | — | 462 | — | 462 | |||||||||||||||||
Other comprehensive income | — | — | 2 | — | — | 2 | |||||||||||||||||
Dividends declared on common stock | — | — | — | (230 | ) | — | (230 | ) | |||||||||||||||
Dividends declared on preferred and preference stock | — | — | — | (29 | ) | — | (29 | ) | |||||||||||||||
Stock-based compensation and other | — | 3 | — | (10 | ) | — | (7 | ) | |||||||||||||||
Noncash stock-based compensation and other | — | 8 | — | — | — | 8 | |||||||||||||||||
Issuance of preference stock | — | (2 | ) | — | — | 125 | 123 | ||||||||||||||||
Balance at June 30, 2011 | $ | 2,168 | $ | 581 | $ | (23 | ) | $ | 5,765 | $ | 1,045 | $ | 9,536 | ||||||||||
Note 3. Variable Interest Entities
Variable Interest in VIEs that are not Consolidated
Power Purchase Contracts
SCE has 16 power purchase agreements ("PPAs") that have variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to fuel the plants and 10 contracts with qualifying facilities ("QFs") that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In general, because payments for capacity are the primary source of income, the most significant economic activity for these VIEs is the operation and maintenance of the power plants.
As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts. Under these contracts, SCE recovers the costs incurred through demonstration of compliance with its CPUC-approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 9. As a result, there is no significant potential exposure to loss as a result of SCE's involvement with these VIEs. The aggregate capacity dedicated to SCE for these VIE projects was 3,820 MW at June 30, 2012 and the amounts that SCE paid to these projects were $57 million and $83 million for the three months ended June 30, 2012 and 2011, respectively, and $134 million and $169 million for the six months ended June 30, 2012 and 2011, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.
Unconsolidated Trust
In May 2012, SCE Trust I issued 5.625% trust securities cumulative, liquidation amount of $25 per share ($475 million aggregate liquidation preference) to the public and $10,000 of common stock (100%) to SCE. The trust invested the proceeds of these trust securities in Series F Preference Stock issued by SCE in the principal amount of $475 million (cumulative, $2,500 per share liquidation value) and which have substantially the same payment terms as the trust securities. The trust securities or the Series F Preference Stock do not have a maturity date. Upon any redemption of the Series F Preference Stock, a corresponding dollar amount of trust securities will be redeemed (for further information see Note 12). SCE Trust I will pay dividends at the same rate and on the same dates on the trust securities when, and if the SCE board of directors declare and make dividend payments on the Series F Preference Stock. The trust will use the dividends, if any, it receives on the Series F Preference Stock to make its corresponding dividends on the trust securities. If SCE does not make dividend payments to the trust, SCE would be prohibited from paying dividends on its common stock. SCE has fully and unconditionally guaranteed the payment of trust securities and also its dividend payments, if and when, SCE pays dividends on the Series F Preference Stock.
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SCE Trust I was formed for the exclusive purpose of issuing trust preference securities (“trust securities”). The trust is a VIE. SCE has concluded that it is not the primary beneficiary of this VIE as it does not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the trust. The trust's balance sheet as of June 30, 2012 consisted of an investment of $475 million in the preference stock, $475 million of trust securities and $10,000 of common stock. The trust's income statement for the three- and six-month periods ended June 30, 2012 consisted of dividend income and accrued dividend payments of $3 million.
Note 4. Fair Value Measurements
Recurring Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price”). Fair value of an asset or liability considers assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk which was not material as of June 30, 2012 and December 31, 2011.
Assets and liabilities are categorized into a three-level fair value hierarchy based on valuation inputs used to determine fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
The following table sets forth assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:
June 30, 2012 | |||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Netting and Collateral1 | Total | ||||||||||||||
Assets at Fair Value | |||||||||||||||||||
Money market funds2 | $ | 5 | $ | — | $ | — | $ | — | $ | 5 | |||||||||
Derivative contracts: | |||||||||||||||||||
Electricity | — | 2 | 21 | (11 | ) | 12 | |||||||||||||
CRRs | — | — | 92 | 92 | |||||||||||||||
Subtotal of derivative contracts | — | 2 | 113 | (11 | ) | 104 | |||||||||||||
Long-term disability plan | 8 | — | — | — | 8 | ||||||||||||||
Nuclear decommissioning trusts: | |||||||||||||||||||
Stocks3 | 2,090 | — | — | — | 2,090 | ||||||||||||||
Municipal bonds | — | 714 | — | — | 714 | ||||||||||||||
U.S. government and agency securities | 389 | 160 | — | — | 549 | ||||||||||||||
Corporate bonds4 | — | 382 | — | — | 382 | ||||||||||||||
Short-term investments, primarily cash equivalents5 | 2 | 90 | — | — | 92 | ||||||||||||||
Subtotal of nuclear decommissioning trusts | 2,481 | 1,346 | — | — | 3,827 | ||||||||||||||
Total assets6 | 2,494 | 1,348 | 113 | (11 | ) | 3,944 | |||||||||||||
Liabilities at Fair Value | |||||||||||||||||||
Derivative contracts: | |||||||||||||||||||
Electricity | — | — | 21 | (11 | ) | 10 | |||||||||||||
Natural gas | — | 194 | 28 | (66 | ) | 156 | |||||||||||||
Tolling | — | — | 803 | — | 803 | ||||||||||||||
Subtotal of derivative contracts | — | 194 | 852 | (77 | ) | 969 | |||||||||||||
Total liabilities | — | 194 | 852 | (77 | ) | 969 | |||||||||||||
Net assets (liabilities) | $ | 2,494 | $ | 1,154 | $ | (739 | ) | $ | 66 | $ | 2,975 | ||||||||
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December 31, 2011 | |||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Netting and Collateral1 | Total | ||||||||||||||
Assets at Fair Value | |||||||||||||||||||
Money market funds2 | $ | 21 | $ | — | $ | — | $ | — | $ | 21 | |||||||||
Derivative contracts: | |||||||||||||||||||
Electricity | — | — | 1 | — | 1 | ||||||||||||||
Natural gas | — | 5 | — | (3 | ) | 2 | |||||||||||||
CRRs | — | — | 122 | — | 122 | ||||||||||||||
Tolling | — | — | 10 | — | 10 | ||||||||||||||
Subtotal of derivative contracts | — | 5 | 133 | (3 | ) | 135 | |||||||||||||
Long-term disability plan | 8 | — | — | — | 8 | ||||||||||||||
Nuclear decommissioning trusts: | |||||||||||||||||||
Stocks3 | 1,899 | — | — | — | 1,899 | ||||||||||||||
Municipal bonds | — | 756 | — | — | 756 | ||||||||||||||
U.S. government and agency securities | 433 | 147 | — | — | 580 | ||||||||||||||
Corporate bonds4 | — | 317 | — | — | 317 | ||||||||||||||
Short-term investments, primarily cash equivalents5 | — | 15 | — | — | 15 | ||||||||||||||
Subtotal of nuclear decommissioning trusts | 2,332 | 1,235 | — | — | 3,567 | ||||||||||||||
Total assets6 | 2,361 | 1,240 | 133 | (3 | ) | 3,731 | |||||||||||||
Liabilities at Fair Value | |||||||||||||||||||
Derivative contracts: | |||||||||||||||||||
Electricity | — | 5 | 65 | (2 | ) | 68 | |||||||||||||
Natural gas | — | 234 | 23 | (53 | ) | 204 | |||||||||||||
Tolling | — | — | 799 | — | 799 | ||||||||||||||
Subtotal of derivative contracts | — | 239 | 887 | (55 | ) | 1,071 | |||||||||||||
Total liabilities | — | 239 | 887 | (55 | ) | 1,071 | |||||||||||||
Net assets (liabilities) | $ | 2,361 | $ | 1,001 | $ | (754 | ) | $ | 52 | $ | 2,660 | ||||||||
1 | Represents the netting of assets and liabilities under master netting agreements and cash collateral across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level. |
2 | Money market funds are included in cash and cash equivalents on SCE's consolidated balance sheets. |
3 | Approximately 67% and 70% of the equity investments were located in the United States at June 30, 2012 and December 31, 2011, respectively. |
4 | At June 30, 2012 and December 31, 2011, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $44 million and $22 million, respectively. |
5 | Excludes net payables of $17 million and net receivables of $25 million at June 30, 2012 and December 31, 2011, respectively, of interest and dividend receivables as well as receivables and payables related to pending securities sales and purchases. |
6 | Excludes other investments of $98 million and $81 million at June 30, 2012 and December 31, 2011, respectively, primarily related to the cash surrender value of company owned life insurance investments which are used to fund certain executive benefits including deferred compensation. |
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The following table sets forth a summary of changes in the fair value of Level 3 net derivative assets and liabilities:
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(in millions) | 2012 | 2011 | 2012 | 2011 | |||||||||||
Fair value of net assets (liabilities) at beginning of period | $ | (1,097 | ) | $ | (127 | ) | $ | (754 | ) | $ | 6 | ||||
Total realized/unrealized gains (losses), net: | |||||||||||||||
Included in regulatory assets1 | 341 | (247 | ) | (23 | ) | (382 | ) | ||||||||
Purchases | 29 | 16 | 50 | 17 | |||||||||||
Settlements | (12 | ) | (1 | ) | (12 | ) | — | ||||||||
Transfers into Level 3 | — | — | — | — | |||||||||||
Transfers out of Level 3 | — | — | — | — | |||||||||||
Fair value of net liabilities at end of period | $ | (739 | ) | $ | (359 | ) | $ | (739 | ) | $ | (359 | ) | |||
Change during the period in unrealized gains (losses) related to assets and liabilities held at the end of the period | $ | 335 | $ | (240 | ) | $ | (8 | ) | $ | (376 | ) | ||||
1 | Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities. |
The fair value for transfers in and transfers out of each level is determined at the end of each reporting period. There were no transfers between Levels 1 and 2 during three- and six-months ended June 30, 2012 and 2011.
Valuation Techniques Used to Determine Fair Value
Level 1
The fair value of Level 1 assets and liabilities is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. This level includes exchange-traded equity securities, U.S. treasury securities and money market funds.
Level 2
The fair value of Level 2 assets and liabilities is determined using the income approach by obtaining quoted prices for similar assets and liabilities in active markets and inputs that are observable, either directly or indirectly, for substantially the full term of the instrument. This level includes fixed income securities and over-the-counter derivatives. For further discussion on fixed income securities, see "—Nuclear Decommissioning Trusts" below.
Over-the-counter derivative contracts are valued using standard pricing models to determine the net present value of estimated future cash flows. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. A primary price source that best represents trade activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes, prices from exchanges or comparison to executed trades are used to validate and corroborate the primary price source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity.
Level 3
The fair value of Level 3 assets and liabilities is determined using the income approach through various models and techniques that require significant unobservable inputs. This level includes over-the-counter options, tolling arrangements and derivative contracts that trade infrequently such as congestion revenue rights ("CRRs") and long-term power agreements.
Assumptions are made in order to value derivative contracts in which observable inputs are not available. Changes in fair value are based on changes to forward market prices, including extrapolation of short-term observable inputs into forecasted prices for illiquid forward periods. In circumstances where fair value cannot be verified with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. Modeling methodologies, inputs and techniques are reviewed and assessed as markets continue to develop and more pricing information becomes available and the fair value is adjusted when it is concluded that a change in inputs or techniques would result in a new valuation that better reflects the fair value of those derivative contracts.
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Level 3 Valuation Process
The process of determining fair value is the responsibility of the risk department which reports to the chief financial officer. This department obtains observable and unobservable inputs through broker quotes, exchanges and internal valuation techniques that use both standard and proprietary models to determine fair value. Each reporting period, the risk and finance departments collaborate to determine the appropriate fair value methodologies and classifications for each derivative. Inputs are validated for reasonableness by comparison against prior prices, other broker quotes and volatility fluctuation thresholds. Inputs used and valuations are reviewed period-over-period and compared with market conditions to determine reasonableness.
The following table sets forth the valuation techniques and significant unobservable inputs used to determine fair value for Level 3 assets and liabilities:
June 30, 2012 | Quantitative Information About Level 3 Fair Value Measurements | |||||||||
Fair Value (in millions) | Significant | Range | ||||||||
Assets | Liabilities | Valuation Technique(s) | Unobservable Input | (Weighted Average) | ||||||
Electricity: | ||||||||||
Options | $ | 42 | $ | 40 | Option model | Volatility of gas prices | 24% – 57% (41%) | |||
Volatility of power prices | 30% – 97% (54%) | |||||||||
Power prices | $34.17 – $56.92 ($42.70) | |||||||||
Forwards | 2 | 4 | Discounted cash flow | Power prices | $13.00 – $47.10 ($28.70) | |||||
Gas Options | — | 28 | Option model | Volatility of gas prices | 27% – 57% (47%) | |||||
CRRs | 92 | — | Market simulation model | Load forecast | 7,645 MW – 26,334 MW | |||||
Power prices | $(46.19) – $240.30 | |||||||||
Gas prices | $3.79 – $9.32 | |||||||||
Tolling | — | 803 | Option model | Volatility of gas prices | 18% – 57% (23%) | |||||
Volatility of power prices | 26% – 97% (31%) | |||||||||
Power prices | $29.89 – $88.04 ($57.30) | |||||||||
Netting | (23 | ) | (23 | ) | ||||||
Total derivative contracts | $ | 113 | $ | 852 | ||||||
Level 3 Fair Value Sensitivity
Gas Options, Electricity Options, and Tolling Arrangements
The fair values of option contracts and tolling arrangements contain intrinsic value and time value. Intrinsic value is the difference between the market price and strike price of the underlying commodity. Time value is made up of several components, including volatility, time to expiration, and interest rates. The fair value of option contracts changes as the underlying commodity price moves away or towards the strike price. The option model for tolling arrangements reflects plant specific information such as operating and start-up costs.
For tolling arrangements and certain gas and power option contracts where SCE is the buyer, increases in volatility of the underlying commodity prices would result in increases to fair value as it represents greater price movement risk. As power and gas prices increase, the fair value of the option contracts and tolling arrangements tends to increase. The valuation of power option contracts and tolling arrangements is also impacted by the correlation between gas and power prices. As the correlation increases, the fair value of power option contracts and tolling arrangements tends to decline.
Forward Power Contracts
Generally, an increase (decrease) in long-term forward power prices at illiquid locations where SCE is the buyer relative to the contract price will increase (decrease) the fair value.
CRRs
Where SCE is the buyer, generally increases (decreases) in forecasted load in isolation would result in increases (decreases) to the fair value. In general, an increase (decrease) in electricity and gas prices at illiquid locations tends to result in increases
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(decreases) to fair value; however, changes in electricity and gas prices in opposite directions may have varying results on fair value.
Nuclear Decommissioning Trusts
SCE's nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information.
Fair Value of Long-Term Debt Recorded at Carrying Value
The carrying value and fair value of long-term debt are:
June 30, 2012 | December 31, 2011 | ||||||||||||||
(in millions) | Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||
Long-term debt, including current portion | $ | 8,827 | $ | 10,368 | $ | 8,431 | $ | 10,129 | |||||||
Fair value of short-term and long-term debt is classified as Level 2 and is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and relevant credit information.
The carrying value of trade receivables and payables, other investments, and short-term debt approximates fair value.
Note 5. Debt and Credit Agreements
Long-Term Debt
In March 2012, SCE issued $400 million of 4.05% first and refunding mortgage bonds due in 2042. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.
Credit Agreements and Short-Term Debt
During the second quarter of 2012, SCE replaced its credit facilities with a $2.75 billion five-year revolving credit facility that matures in May 2017. The credit facility is generally used to support commercial paper and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working capital requirements to support operations and capital expenditures. At June 30, 2012, SCE's outstanding commercial paper supported by the credit facility was $300 million at a weighted-average interest rate of 0.43%. At June 30, 2012, letters of credit issued under SCE's credit facility aggregated $63 million and are scheduled to expire in twelve months or less.
At December 31, 2011, the outstanding commercial paper was $419 million at a weighted-average interest rate of 0.44%.
Note 6. Derivative Instruments and Hedging Activities
Commodity Price Risk
SCE is exposed to commodity price risk which represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's hedging program reduces customer exposure to variability in market prices related to SCE's power and gas activities. As part of this program, SCE enters into options, swaps, forwards, tolling arrangements and CRRs. These transactions are approved by the CPUC or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the energy resource recovery account ("ERRA") balancing account, and as a result, exposure to commodity price risk is not expected to impact earnings, but may impact cash flows.
SCE's electricity price exposure arises from energy purchased from and sold to wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities and power purchase agreements.
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SCE's natural gas price exposure arises from natural gas purchased for the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas index and power purchase agreements in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging activities:
Economic Hedges | |||||
Commodity | Unit of Measure | June 30, 2012 | December 31, 2011 | ||
Electricity options, swaps and forwards | GWh | 26,597 | 30,881 | ||
Natural gas options, swaps and forwards | Bcf | 213 | 300 | ||
Congestion revenue rights | GWh | 136,863 | 166,163 | ||
Tolling arrangements | GWh | 102,819 | 104,154 | ||
Fair Value of Derivative Instruments
The following table summarizes the gross and net fair values of commodity derivative instruments at June 30, 2012:
Derivative Assets | Derivative Liabilities | |||||||||||||||||||||||||||
(in millions) | Short-Term | Long-Term | Subtotal | Short-Term | Long-Term | Subtotal | Net Liability | |||||||||||||||||||||
Non-trading activities | ||||||||||||||||||||||||||||
Economic hedges | $ | 69 | $ | 75 | $ | 144 | $ | 245 | $ | 830 | $ | 1,075 | $ | 931 | ||||||||||||||
Netting and collateral | (24 | ) | (16 | ) | (40 | ) | (72 | ) | (34 | ) | (106 | ) | (66 | ) | ||||||||||||||
Total | $ | 45 | $ | 59 | $ | 104 | $ | 173 | $ | 796 | $ | 969 | $ | 865 | ||||||||||||||
The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2011:
Derivative Assets | Derivative Liabilities | |||||||||||||||||||||||||||
(in millions) | Short-Term | Long-Term | Subtotal | Short-Term | Long-Term | Subtotal | Net Liability | |||||||||||||||||||||
Non-trading activities | ||||||||||||||||||||||||||||
Economic hedges | $ | 86 | $ | 85 | $ | 171 | $ | 303 | $ | 856 | $ | 1,159 | $ | 988 | ||||||||||||||
Netting and collateral | (21 | ) | (15 | ) | (36 | ) | (37 | ) | (51 | ) | (88 | ) | (52 | ) | ||||||||||||||
Total | $ | 65 | $ | 70 | $ | 135 | $ | 266 | $ | 805 | $ | 1,071 | $ | 936 | ||||||||||||||
Income Statement Impact of Derivative Instruments
SCE recognizes realized gains and losses on derivative instruments as purchased power expense and expects that such gains or losses will be part of the purchase power costs recovered from customers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from customers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.
The following table summarizes the components of economic hedging activity:
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(in millions) | 2012 | 2011 | 2012 | 2011 | |||||||||||
Realized gains (losses) | $ | (67 | ) | $ | (35 | ) | $ | (122 | ) | $ | (74 | ) | |||
Unrealized gains (losses) | 423 | (227 | ) | 62 | (323 | ) | |||||||||
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Contingent Features/Credit Related Exposure
Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. SCE has provided collateral in the form of cash and/or letters of credit for the benefit of counterparties. These requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments and other factors.
Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies, referred to as a credit-risk-related contingent feature. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate fair value of all derivative liabilities with these credit-risk-related contingent features was $96 million and $216 million as of June 30, 2012 and December 31, 2011, respectively, for which SCE has posted no collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2012, SCE would be required to post $52 million of collateral.
Counterparty Default Risk Exposure
As part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments. Substantially all of the contracts that SCE has executed with counterparties are either entered into under SCE's procurement plan which has been pre-approved by the CPUC, or the contracts are approved by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not expected to affect earnings, but may temporarily affect cash flows.
To manage credit risk, SCE looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary.
Margin and Collateral Deposits
Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the related positions. SCE nets counterparty receivables and payables where balances exist under master netting agreements. SCE presents the portion of its margin and collateral deposits netted with its derivative positions on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to counterparties:
(in millions) | June 30, 2012 | December 31, 2011 | |||||
Collateral provided to counterparties: | |||||||
Offset against derivative liabilities | $ | 66 | $ | 51 | |||
Reflected in other current assets | 25 | 17 | |||||
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Note 7. Income Taxes
Effective Tax Rate
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(in millions) | 2012 | 2011 | 2012 | 2011 | |||||||||||
Income before income taxes | $ | 322 | $ | 354 | $ | 622 | $ | 713 | |||||||
Provision for income tax at federal statutory rate of 35% | 113 | 124 | 218 | 249 | |||||||||||
Increase (decrease) in income tax from: | |||||||||||||||
State tax – net of federal benefit | 10 | 18 | 20 | 30 | |||||||||||
Property-related | (10 | ) | (10 | ) | (20 | ) | (21 | ) | |||||||
Other | (5 | ) | (4 | ) | (10 | ) | (7 | ) | |||||||
Total income tax expense | $ | 108 | $ | 128 | $ | 208 | $ | 251 | |||||||
Effective tax rate | 33.5 | % | 36.2 | % | 33.4 | % | 35.2 | % | |||||||
The CPUC requires flow-through ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.
Tax Dispute
Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 are currently under review by the Franchise Tax Board. The IRS examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010. This included a proposed adjustment to disallow a component of SCE's repair allowance deduction, which if sustained, would result in a federal tax payment of approximately $95 million, including interest through June 30, 2012. Edison International disagrees with the proposed adjustment and filed a protest with the IRS in the first quarter of 2011.
Note 8. Pension Plans and Postretirement Benefits Other Than Pensions
Pension Plans
As part of the pension funding provisions contained in the Surface Transportation Extension Act of 2012 passed by Congress in June 2012, SCE's projected 2012 plan contributions have been reduced to $172 million from $263 million, pending a final interest rate to be issued by the IRS. SCE made contributions of $55 million during the six months ended June 30, 2012 and in July 2012, made a further required $58 million contribution to the pension fund. Contributions to date exceed the $55 million currently being collected through customer rates. In the 2012 GRC, SCE requested recovery of plan contributions of $168 million with recovery of any undercollection through the continuation of the existing balancing account mechanism. This proposal has been challenged by intervenors and is pending the outcome of the 2012 GRC decision. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.
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Expense components are:
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(in millions) | 2012 | 2011 | 2012 | 2011 | |||||||||||
Service cost | $ | 37 | $ | 38 | $ | 74 | $ | 76 | |||||||
Interest cost | 45 | 47 | 90 | 94 | |||||||||||
Expected return on plan assets | (55 | ) | (56 | ) | (110 | ) | (112 | ) | |||||||
Amortization of prior service cost | 1 | 2 | 2 | 4 | |||||||||||
Amortization of net loss | 15 | 4 | 30 | 8 | |||||||||||
Expense under accounting standards | $ | 43 | $ | 35 | $ | 86 | $ | 70 | |||||||
Regulatory adjustment (deferred) | 27 | (6 | ) | 54 | (12 | ) | |||||||||
Total expense recognized | $ | 70 | $ | 29 | $ | 140 | $ | 58 | |||||||
Postretirement Benefits Other Than Pensions
SCE made contributions of $10 million during the six months ended June 30, 2012 and expects to make $52 million of additional contributions during the remainder of 2012. SCE's 2012 annual contributions are expected to be recovered through CPUC-approved regulatory mechanisms. Annual contributions are expected to be, at a minimum, equal to the total annual expense for these plans. Benefits under these plans, with some exceptions, are generally unvested and subject to change.
Expense components are:
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(in millions) | 2012 | 2011 | 2012 | 2011 | |||||||||||
Service cost | $ | 12 | $ | 10 | $ | 24 | $ | 20 | |||||||
Interest cost | 28 | 31 | 56 | 62 | |||||||||||
Expected return on plan assets | (27 | ) | (27 | ) | (54 | ) | (54 | ) | |||||||
Amortization of prior service credit | (9 | ) | (9 | ) | (18 | ) | (18 | ) | |||||||
Amortization of net loss | 11 | 9 | 22 | 18 | |||||||||||
Total expense | $ | 15 | $ | 14 | $ | 30 | $ | 28 | |||||||
Transfer of Certain Postretirement Benefits to Edison International
In March 2012, Edison International agreed to assume the liabilities for active employees of SCE and its subsidiaries under the specified plans related to deferred compensation and executive post retirement benefits. SCE is obligated to reimburse Edison International upon settlement of liabilities on an after tax basis. Included in the consolidated balance sheet at June 30, 2012 was $113 million related to this obligation.
Note 9. Commitments and Contingencies
Third-Party Power Purchase Agreements
During the six months ended June 30, 2012, SCE had new power purchase contracts classified as operating leases. The additional commitments are estimated to be: $21 million in 2015, $45 million in 2016 and $944 million for the period remaining thereafter.
In July 2012, SCE entered into new power purchase contracts with commitments estimated to be: $51 million in 2014, $53 million in 2015, $50 million in 2016 and $199 million for the period remaining thereafter.
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Indemnities
Indemnity Provided as Part of the Acquisition of Mountainview
In connection with the acquisition of the Mountainview power plant, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.
Mountainview Filter Cake Indemnity
SCE has indemnified the City of Redlands, California in connection with Mountainview's California Energy Commission permit for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this indemnity.
Other Indemnities
SCE provides other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and indemnities for specified environmental liabilities and income taxes with respect to assets sold. SCE's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties. SCE has not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.
Contingencies
In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. SCE believes the outcome of these other proceedings, individually and in the aggregate, will not materially affect its results of operations or liquidity.
San Onofre Outage, Inspection and Repair Issues
SCE replaced four steam generators at San Onofre Units 2 and 3 in 2010 and 2011. In the first quarter of 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. Unit 3 was safely taken off-line. At the time, San Onofre Unit 2 was off-line for a planned outage when isolated areas of wear in some of its heat transfer tubes were found. Both Units remain off-line for ongoing, extensive inspections, testing and analysis of their steam generators, and will be restarted only when SCE determines that it is safe to do so and when start-up has been approved by the NRC.
In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million after adjustment for inflation) for SCE's 78.21% share of San Onofre to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $593 million through June 30, 2012 on the steam generator replacement project. Those expenditures remain subject to CPUC reasonableness review upon submission of SCE's final costs for the overall project.
As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre is being purchased in the market by SCE on behalf of customers (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market costs through June 30, 2012 were approximately $117 million, net of avoided nuclear fuel costs, and are recoverable through the ERRA balancing account, subject to CPUC reasonableness review. Because of the uncertainties associated with when and at what output levels the Units will or may be returned to service, total potential market power costs cannot be estimated at this time. Costs for power are likely to be higher during the summer months.
SCE's 2012 annual revenue requirement request for its direct operating and maintenance costs, depreciation and return on its investment in San Onofre Unit 2, Unit 3 and related common plant is approximately $650 million. At June 30, 2012, San Onofre rate base was $1.2 billion and the net investment and related inventory associated with San Onofre was $2.0 billion. Under California Public Utilities Code Section 455.5, SCE will be required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months, or November 2012 for Unit 3 and December 2012 for Unit 2 (not including preplanned outages). In that event, the CPUC is required within 45 days of SCE's notice for a particular Unit to
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initiate an investigation to determine whether to remove from customer rates some or all of the revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such rates are collected subject to refund. Under Section 455.5 any determination to adjust rates is made after hearings are conducted in connection with the utility's next general rate case. If, after investigation and hearings, the costs associated with a Unit are disallowed recovery because it is out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation. Notwithstanding the requirements of Section 455.5, the CPUC may institute other proceedings relating to the impact of the extended outage at San Onofre and its potential effects on rates, and there is currently pending before the CPUC a proposal to initiate an Order Instituting Investigation regarding such impacts.
The steam generators were designed and supplied by MHI and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. SCE's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $137 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions. In addition, San Onofre carries both property damage and outage insurance for San Onofre issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of potential claims for loss recovery. SCE will pursue recoveries arising from available agreements and insurance, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements.
CPSD Investigations
San Gabriel Valley Windstorm Investigation
In November 2011, a windstorm resulted in significant damage to SCE’s electric system and service outages for SCE customers primarily in the San Gabriel Valley. The CPUC directed its Consumer Protection and Safety Division (“CPSD”) to conduct an investigation focused on the cause of the outages, SCE’s service restoration effort, and SCE’s customer communications during the outages. The CPSD issued its preliminary report on February 1, 2012. The report asserts that SCE and others with whom SCE shares utility poles violated certain CPUC safety rules applicable to overhead line construction, maintenance and operation, which may have caused the failures of affected poles and supporting cables. The report also concludes that SCE’s restoration time was not adequate and makes other assertions. Additionally, the report contends that SCE violated CPUC rules by failing to preserve evidence relevant to the investigation when it did not retain damaged poles that were replaced following the windstorm. If the CPUC issues an Order Instituting Investigation ("OII") regarding this matter and SCE is found to have violated any CPUC rules, it could face penalties. In addition, the cost of any large scale review of poles or other equipment for safety compliance could be significant. SCE is unable to estimate a possible loss or range of loss associated with any penalties that may be imposed by the CPUC on SCE.
Malibu Fire Order Instituting Investigation
Following a 2007 wildfire in Malibu, California, the CPUC issued an OII to determine if any statutes, CPUC general orders, rules or regulations were violated by SCE or telecomm providers (“OII Respondents”) that shared the use of three failed power poles in the wildfire area. The CPSD has alleged, among other things, that the poles were overloaded, that the OII Respondents violated the CPUC's rules governing the design, construction and inspection of poles and misled the CPUC during its investigation of the fire, and that SCE failed to preserve evidence relevant to the investigation. In October 2011, the CPSD proposed that the OII Respondents be assessed penalties of approximately $99 million, with SCE being allocated approximately $50 million of the total. SCE has denied the allegations and believes the proposed penalties are excessive.
Four Corners New Source Review Litigation
In October 2011, four private environmental organizations filed a CAA citizen lawsuit against the co-owners of Four Corners. The complaint alleges that certain work performed at the Four Corners generating units 4 and 5, over the approximate periods of 1985-1986 and 2007-present, constituted plant “major modifications” and the plant's failure to obtain permits and install best available control technology ("BACT") violated the PSD requirements and the New Source Performance Standards of the CAA. The complaint also alleges subsequent and continuing violations of BACT air emissions limits. The lawsuit seeks injunctive and declaratory relief, civil penalties, including a mitigation project and litigation costs. In November 2010, SCE entered into an agreement to sell its ownership interest in generating units 4 and 5 to APS. The sale is subject to certain closing conditions and is expected to close not earlier than December 2012. Under the agreement SCE would remain responsible for its pro rata share of certain environmental liabilities, including penalties arising from environmental violations prior to the sale, but SCE would not be liable for any costs of installing BACT or other costs related to continuing or extending Four Corners operations. SCE is unable to estimate a possible loss or range of loss associated with this matter.
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Concurrently, the US EPA has proposed a regional haze federal implementation plan based on an APS proposal that would require shut down of units 1, 2 and 3 by 2016 and the installation of selective catalytic reduction technology on units 4 and 5 by 2018. APS' proposal contemplated that these actions would both satisfy the federal regional haze requirements and resolve any New Source Review claims the US EPA might have. A final federal implementation plan is expected in 2012.
Environmental Remediation
SCE records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operation and maintenance, monitoring and site closure. Unless there is a single probable amount, SCE records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.
At June 30, 2012, SCE's recorded estimated minimum liability to remediate its 25 identified material sites (sites in which the upper end of the range of the costs is at least $1 million) and 33 identified immaterial sites was $43 million (which includes $11 million related to San Onofre) and $3 million, respectively. Of the $46 million total environmental remediation liability, $43 million has been recorded as a regulatory asset. SCE expects to recover $28 million through an incentive mechanism that allows SCE to recover 90% of its environmental remediation costs at certain sites (SCE may request to include additional sites) and $15 million through a mechanism that allows SCE to recover 100% of the costs incurred at certain sites through customer rates. SCE's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.
The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs at the identified material sites and immaterial sites could exceed its recorded liability by up to $216 million and $6 million, respectively. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next five years are expected to range from $7 million to $17 million. Costs incurred for the six months ended June 30, 2012 and 2011 were $4 million and $7 million, respectively.
Based upon the CPUC's regulatory treatment of environmental remediation costs, SCE believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $12.6 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($375 million). The balance is covered by a loss sharing program among nuclear reactor licensees. If a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.
Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per incident in any one year. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.
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NEIL, a mutual insurance company owned by entities with nuclear facilities, issues primary property damage, decontamination and excess property damage and accidental outage insurance policies. At San Onofre and Palo Verde, property damage insurance covers losses up to $500 million, including decontamination costs. Decontamination liability and excess property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than the federal requirement of a minimum of approximately $1.1 billion. Property damage insurance also covers damages caused by acts of terrorism up to specified limits. Additional outage insurance covers part of replacement power expenses during an accident-related nuclear unit outage.
If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $49 million per year. Insurance premiums are charged to operating expense.
Wildfire Insurance
Severe wildfires in California have given rise to large damage claims against California utilities for fire-related losses alleged to be the result of the failure of electric and other utility equipment. Invoking a California Court of Appeal decision, plaintiffs pursuing these claims have relied on the doctrine of inverse condemnation, which can impose strict liability (including liability for a claimant's attorneys' fees) for property damage. On September 1, 2011, SCE's parent, Edison International, renewed its insurance coverage, which included coverage for SCE's wildfire liabilities up to a $575 million limit (with a self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the insurance coverage could result in additional self-insured costs in the event of multiple wildfire occurrences during the policy period (September 1, 2011 to August 31, 2012). SCE may experience coverage reductions and/or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of SCE's insurance coverage.
Spent Nuclear Fuel
Under federal law, the Department of Energy ("DOE") is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for the current license period.
In June 2010, the United States Court of Federal Claims issued a decision granting SCE and the San Onofre co-owners damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. SCE received payment from the federal government in the amount of the damage award in November 2011. SCE has returned to the San Onofre co-owners their respective share of the damage award paid. SCE, as operating agent, filed a lawsuit on behalf of the San Onofre owners against the DOE in the Court of Federal Claims in December 2011 seeking damages of approximately $98 million for the period from January 1, 2006 to December 31, 2010 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel. Additional legal action would be necessary to recover damages incurred after December 31, 2010. Any damages recovered by SCE are subject to CPUC review as to how these amounts would be distributed among customers, shareholders, or to offset fuel decommissioning or storage costs.
Note 10. Environmental Developments
Greenhouse Gas Regulation
In March 2012, the US EPA announced proposed carbon dioxide emissions limits for new power plants. The status of the US EPA's efforts to develop greenhouse gas emissions performance standards for existing plants is unknown.
In June 2012, the U.S. Court of Appeals for the D.C. Circuit dismissed the challenge by industry groups and some states to the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule."
In July 2012, the US EPA published a final rule maintaining the CO2 equivalent emissions thresholds (for purposes of PSD and Title V permitting) originally established in the GHG tailoring rule.
Greenhouse Gas Litigation
In March 2012, the federal district court in Mississippi dismissed, in its entirety, the purported class action complaint filed by private citizens in May 2011, naming a large number of defendants, including SCE and other Edison International subsidiaries, for damages allegedly arising from Hurricane Katrina. In April 2012, the plaintiffs filed an appeal with the Fifth Circuit Court of Appeals. Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of
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greenhouse gases that have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset of the claims that were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal district court where the current case has been filed.
Note 11. Supplemental Cash Flows Information
SCE's supplemental cash flows information is:
Six months ended June 30, | |||||||
(in millions) | 2012 | 2011 | |||||
Cash payments (receipts) for interest and taxes: | |||||||
Interest – net of amounts capitalized | $ | 194 | $ | 179 | |||
Tax refunds – net | (2 | ) | (95 | ) | |||
Details of debt exchange: | |||||||
Pollution-control bonds redeemed | $ | — | $ | (56 | ) | ||
Pollution-control bonds issued | — | 56 | |||||
Dividends declared but not paid: | |||||||
Preferred and preference stock | $ | 34 | $ | 15 | |||
Accrued capital expenditures at June 30, 2012 and 2011 were $408 million and $341 million, respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flow in the period paid.
Note 12. Preferred and Preference Stock
During the first quarter of 2012, SCE issued 350,000 shares of 6.25% Series E Preference Stock (cumulative, $1,000 liquidation value). The Series E preference shares may not be redeemed prior to February 1, 2022. After February 1, 2022, SCE may at its option, redeem the shares, in whole or in part for a price of $1,000 per share plus accrued and unpaid dividends, if any. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to repay commercial paper borrowings and to fund SCE's capital program.
During the second quarter of 2012, SCE issued 190,004 shares of 5.625% Series F Preference Stock (cumulative, $2,500 liquidation value) to SCE Trust I, a special purpose entity formed to issue trust securities as discussed in Note 3. Variable Interest Entities. The Series F Preference Stock may not be redeemed prior to June 15, 2017. After June 15, 2017, SCE may at its option, redeem the shares, in whole or in part for a price of $2,500 per share plus accrued and unpaid dividends, if any. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to repay commercial paper borrowings, for general corporate purposes and to redeem and retire $75 million of the Series A Preference Stock.
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Note 13. Regulatory Assets and Liabilities
Regulatory Assets
Regulatory assets included on the consolidated balance sheets are:
(in millions) | June 30, 2012 | December 31, 2011 | |||||
Current: | |||||||
Regulatory balancing accounts | $ | 351 | $ | 223 | |||
Energy derivatives | 227 | 264 | |||||
Other | 8 | 7 | |||||
Total Current | 586 | 494 | |||||
Long-term: | |||||||
Deferred income taxes – net | 2,097 | 2,020 | |||||
Pensions and other postretirement benefits | 1,672 | 1,703 | |||||
Energy derivatives | 809 | 836 | |||||
Unamortized investments - net | 483 | 484 | |||||
Unamortized loss on reacquired debt | 238 | 249 | |||||
Nuclear-related investment – net | 149 | 156 | |||||
Regulatory balancing accounts | 92 | 69 | |||||
Other | 236 | 298 | |||||
Total Long-term | 5,776 | 5,815 | |||||
Total Regulatory Assets | $ | 6,362 | $ | 6,309 | |||
Regulatory Liabilities
Regulatory liabilities included on the consolidated balance sheets are:
(in millions) | June 30, 2012 | December 31, 2011 | |||||
Current: | |||||||
Regulatory balancing accounts | $ | 712 | $ | 661 | |||
Other | 9 | 9 | |||||
Total Current | 721 | 670 | |||||
Long-term: | |||||||
Costs of removal | 2,742 | 2,697 | |||||
Asset Retirement Obligations | 1,235 | 1,105 | |||||
Regulatory balancing accounts | 1,054 | 864 | |||||
Other | 7 | 4 | |||||
Total Long-term | 5,038 | 4,670 | |||||
Total Regulatory Liabilities | $ | 5,759 | $ | 5,340 | |||
Note 14. Other Investments
Nuclear Decommissioning Trusts
Future decommissioning costs of removal of nuclear assets are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $23 million per year through SCE customer rates. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates. Funds collected,
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together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.
The following table sets forth amortized cost and fair value of the trust investments:
Amortized Cost | Fair Value | ||||||||||||||||
(in millions) | Longest Maturity Dates | June 30, 2012 | December 31, 2011 | June 30, 2012 | December 31, 2011 | ||||||||||||
Stocks | — | $ | 953 | $ | 865 | $ | 2,090 | $ | 1,899 | ||||||||
Municipal bonds | 2051 | 583 | 625 | 714 | 756 | ||||||||||||
U.S. government and agency securities | 2041 | 489 | 516 | 549 | 580 | ||||||||||||
Corporate bonds | 2054 | 310 | 259 | 382 | 317 | ||||||||||||
Short-term investments and receivables/payables | One-year | 71 | 38 | 75 | 40 | ||||||||||||
Total | $ | 2,406 | $ | 2,303 | $ | 3,810 | $ | 3,592 | |||||||||
Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $496 million and $524 million for the three months ended June 30, 2012 and 2011, respectively, and $1.1 billion for both the six months ended June 30, 2012 and 2011. Unrealized holding gains, net of losses, were $1.4 billion and $1.3 billion at June 30, 2012 and December 31, 2011, respectively.
The following table sets forth a summary of changes in the fair value of the trust:
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(in millions) | 2012 | 2011 | 2012 | 2011 | |||||||||||
Balance at beginning of period | $ | 3,853 | $ | 3,619 | $ | 3,592 | $ | 3,480 | |||||||
Gross realized gains | 15 | 12 | 40 | 35 | |||||||||||
Gross realized losses | (1 | ) | — | (5 | ) | — | |||||||||
Unrealized gains (losses) – net | (67 | ) | 4 | 116 | 106 | ||||||||||
Other-than-temporary impairments | (19 | ) | (4 | ) | (23 | ) | (13 | ) | |||||||
Interest, dividends, contributions and other | 29 | 26 | 90 | 49 | |||||||||||
Balance at end of period | $ | 3,810 | $ | 3,657 | $ | 3,810 | $ | 3,657 | |||||||
Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on operating revenue or earnings.
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Note 15. Other Income and Expenses
Other income and expenses are as follows:
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(in millions) | 2012 | 2011 | 2012 | 2011 | |||||||||||
Other income: | |||||||||||||||
Equity allowance for funds used during construction | $ | 27 | $ | 27 | $ | 47 | $ | 56 | |||||||
Increase in cash surrender value of life insurance policies | 7 | 7 | 14 | 13 | |||||||||||
Other | 2 | 5 | 6 | 8 | |||||||||||
Total other income | $ | 36 | $ | 39 | $ | 67 | $ | 77 | |||||||
Other expenses: | |||||||||||||||
Civic, political and related activities and donations | $ | 10 | $ | 9 | $ | 17 | $ | 15 | |||||||
Other | 9 | 4 | 9 | 10 | |||||||||||
Total other expenses | $ | 19 | $ | 13 | $ | 26 | $ | 25 | |||||||
Note 16. Planned Sale of Interest in Four Corners
In November 2010, SCE entered into an agreement to sell its ownership interest in Units 4 and 5 of the Four Corners Generating Station, a coal-fired electric generating facility in New Mexico, to the operator of the facility, Arizona Public Service Company. During 2012, the CPUC and the Arizona Corporation Commission ("ACC") approved the transaction. As part of its sale approval, the ACC stipulated that the sale cannot close earlier than December 1, 2012 which under the adjustment mechanism set forth in the sales agreement would reduce the sale price from $294 million to $279 million. The price is also subject to further adjustments. The closing of the sale is contingent upon the receipt of other specified closing conditions, including APS obtaining a long-term fuel supply agreement for the plant. The sale agreement provides for either party to terminate if it is not completed by December 31, 2012. Any gain on the sale will be for the benefit of SCE's customers and, therefore, will not affect SCE's earnings.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This quarterly report on Form 10-Q contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect SCE's current expectations and projections about future events based on SCE's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by SCE that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact SCE, include, but are not limited to:
• | ability of SCE to recover its costs in a timely manner from its customers through regulated rates; |
• | decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions; |
• | possible customer bypass or departure due to technological advancements or cumulative rate impacts that make self-generation or use of alternative energy sources economically viable; |
• | risks inherent in the construction of transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable the acceptance of power delivery), and governmental approvals; |
• | risks associated with the operation of transmission and distribution assets and nuclear and other power generating facilities including: nuclear fuel storage issues, public safety issues, failure, availability, efficiency, output, cost of repairs and retrofits of equipment and availability and cost of spare parts; |
• | environmental laws and regulations, both at the state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business; |
• | cost of capital and the ability to borrow funds and access to capital markets on reasonable terms; |
• | the cost and availability of electricity including the ability to procure sufficient resources to meet expected customer needs to replace power that would have been provided by San Onofre but for the current outage or in the event of other power plant outages or significant counterparty defaults under power-purchase agreements; |
• | changes in the fair value of investments and other assets; |
• | changes in interest rates and rates of inflation, including those rates which may be adjusted by public utility regulators; |
• | governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by Independent System Operators and Regional Transmission Organizations; |
• | availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations; |
• | cost and availability of labor, equipment and materials; |
• | ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance or in the absence of insurance the ability to recover uninsured losses; |
• | effects of legal proceedings, changes in or interpretations of tax laws, rates or policies; |
• | potential for penalties or disallowances caused by non-compliance with applicable laws and regulations; |
• | cost and availability of coal, natural gas, fuel oil, and nuclear fuel, and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts; |
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• | cost and availability of emission credits or allowances for emission credits; |
• | transmission congestion in and to each market area and the resulting differences in prices between delivery points; |
• | ability to provide sufficient collateral in support of hedging activities and power and fuel purchased; |
• | risks that competing transmission systems will be built by merchant transmission providers in SCE's service area; and |
• | weather conditions and natural disasters. |
Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in SCE's 2011 Form 10-K, including the "Risk Factors" section in Part I, Item 1A. Readers are urged to read this entire report, including the information incorporated by reference, as well as the 2011 Form 10-K, and carefully consider the risks, uncertainties and other factors that affect SCE's business. Forward-looking statements speak only as of the date they are made and SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE with the U.S. Securities and Exchange Commission.
The MD&A for the three- and six-month periods ended June 30, 2012 discusses material changes in the consolidated financial condition, results of operations and other developments of SCE since December 31, 2011 and as compared to the three- and six-month periods ended June 30, 2011. This discussion presumes that the reader has read or has access to SCE's MD&A for the calendar year 2011 (the "year-ended 2011 MD&A"), which was included in the 2011 Form 10-K.
MANAGEMENT OVERVIEW
Highlights of Operating Results
Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
(in millions) | 2012 | 2011 | Change | 2012 | 2011 | Change | |||||||||||||||||
Core earnings | $ | 191 | $ | 211 | $ | (20 | ) | $ | 373 | $ | 433 | $ | (60 | ) | |||||||||
Non-core items | — | — | — | — | — | — | |||||||||||||||||
Net income available for common stock | $ | 191 | $ | 211 | $ | (20 | ) | $ | 373 | $ | 433 | $ | (60 | ) | |||||||||
SCE's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings for financial planning and for analysis of performance. Core earnings are also used when communicating with analysts and investors regarding SCE's earnings results to facilitate comparisons of the performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to SCE less income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: settlement of certain tax, regulatory or legal matters or proceedings.
SCE's 2012 core earnings decreased $20 million and $60 million for the quarter and year-to-date, respectively. Core earnings in both periods decreased primarily due to a delay in the 2012 CPUC General Rate Case decision as higher depreciation and net interest expenses are not being recovered in currently authorized revenue. The revenue requirement ultimately adopted by the CPUC will be retroactive to January 1, 2012. SCE has incurred $29 million and $48 million of incremental steam generator inspection and repair costs related to outages at San Onofre for the quarter and year-to-date periods, respectively, which are currently being offset by other operation and maintenance cost reductions. The year-to-date variance also reflects a lower capitalization rate on funds used during construction.
2012 CPUC General Rate Case
As discussed in the year-ended 2011 MD&A, SCE filed its 2012 GRC application in November 2010. In October 2011, SCE submitted updated testimony, which changed SCE's requested 2012 base rate revenue requirement to $6.3 billion. The Division of Ratepayer Advocates, The Utility Reform Network and other intervenors recommended substantially less than the amount requested by SCE. Intervenors have also recommended changes to SCE's proposed post-test year ratemaking methodology to be used for 2013 and 2014 as well as limiting the recovery amount of SCE's pension costs. A decision on the GRC is expected in the second half of 2012. SCE is currently recognizing revenue largely based on the 2011 authorized revenue requirement, however, the CPUC has authorized the establishment of a GRC memorandum account, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.
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2013 Cost of Capital Application
In June 2012, the CPUC issued an order in the 2013 Cost of Capital proceeding consolidating SCE's 2013 application with the four other California investor-owned utilities' applications and splitting the proceeding into two phases. The first phase will address the 2013 ratemaking capital structure and cost of capital for the utilities and contemplates a final decision in December 2012. The second phase will consider whether the current multi-year mechanism should be continued or modified. The schedule for the second phase is to be set by the end of 2012.
SCE's 2013 cost of capital application, which was filed in April 2012, requested a ratemaking capital structure of 43% long-term debt, 9% preferred equity and 48% common equity consistent with the current capital structure. In addition, SCE proposed reducing its current cost of capital as follows: cost of long-term debt from 6.22% to 5.53%, authorized cost of preferred equity from 6.01% to 5.86% and authorized return on common equity from 11.5% to 11.1%. SCE's application included a revenue requirement reduction estimate of $128 million for 2013. The application also requested the continuation of the current multi-year mechanism, which would have retained the authorized capital structure through 2015 subject to annual adjustments if certain thresholds are reached.
San Onofre Outage, Inspection and Repair Issues
As discussed in the 2011 Form 10-K, four replacement steam generators were installed at San Onofre Units 2 and 3 in 2010 and 2011, respectively. In the first quarter of 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. Unit 3 was safely taken off-line. At the time, San Onofre Unit 2 was off-line for a planned outage when areas of unexpected wear in some of its heat transfer tubes were found. Both Units remain off-line for ongoing, extensive inspections, testing and analysis of their steam generators, and will be restarted only when SCE determines that it is safe to do so and when start-up has been approved by the NRC pursuant to the terms of a Confirmatory Action Letter described below.
Tube Leak and Repairs
The water leak in the Unit 3 steam generator was caused by excessive wear resulting from tube-to-tube contact in the area of the leak. During the inspection and testing of the Unit 3 steam generators, additional pressure tests of certain tubes were completed to determine the safety significance of the wear. Eight of the 129 tubes subjected to the additional tests failed the tests for structural integrity as a result of excessive wear, and the NRC was notified as required. The same areas were re-inspected in the Unit 2 steam generators using a more sensitive inspection method than had previously been employed, and similar wear from tube-to-tube contact was found on two tubes in one of the steam generators at wear levels below the detection capability of the initial inspection.
Earlier tests performed on the Unit 2 steam generators during the planned outage additionally found high levels of unexpected wear in some tubes that were in contact with retainer bars of the tube support structure. As a result, all such tubes in contact with retainer bars in both Unit 2 steam generators were preventively removed from service through plugging. Subsequent inspections on Unit 3 found similar tube-to-support structure wear, and the Unit 3 tubes in contact with the retainer bars have also been plugged preventively. Each steam generator has over 9,700 heat transfer tubes and is designed to include sufficient tubes to accommodate a need to remove some from service for a variety of reasons, and the tubes that SCE has preventively removed from service are within this margin.
SCE understands that the tube-to-tube contact arises from excessive vibration of the tubes in certain areas of the steam generators. The excessive vibration is caused, at least in substantial part, by a phenomenon called fluid elastic instability which results from the interaction of a combination of factors, including steam velocity, moisture content of the steam, and effectiveness of the supports in the areas where the vibration occurs. A team of outside experts has been assembled to assist SCE and Mitsubishi Heavy Industries, Inc. (“MHI”), the manufacturer of the steam generators, in the analysis of the causes of the tube-to-tube wear and potential remedial actions.
Any remedial action that will permit restart of one or both of the Units will need to address the interaction of factors giving rise to the fluid elastic instability. Until further actions are completed, including the NRC processes discussed below, the schedule to restart these Units cannot be determined. Because Unit 2 experienced considerably less tube-to-tube wear, it is currently anticipated that it could restart in advance of Unit 3; however, in order to do so, it is expected that pending further repairs and analysis, it would operate at reduced power levels and with mid-cycle scheduled outages to provide assurance of safe operation. Inasmuch as Unit 3 had much more tube-to-tube wear than Unit 2, it is not clear at this time whether Unit 3 will be able to restart without extensive additional repairs, meaning that it would be less likely to restart this year. The current plan for Unit 3 is to de-fuel the reactor and place appropriate systems in a lay up condition while analysis and testing continue given the uncertain timing of the likely repairs and restart. SCE is engaged in the analysis of what repairs, if any, could be undertaken to restore the steam generators to their originally specified capabilities safely, but it has not determined
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what those repairs might be or whether the generators will need to be replaced for the Units to operate at their prior output levels.
NRC Processes
The timing of restart of the Units will also be affected by the nature of and schedule for regulatory processes required by the NRC.
Following the failure of pressure tests on the eight tubes in Unit 3, the NRC launched an Augmented Inspection Team (“AIT”) to assess the tube failures and their causes, SCE's operation of the Units, and SCE's oversight of the design, fabrication, shipping, and construction process. On July 19, 2012, the NRC issued a report providing the results of the AIT inspection. That report concluded that the replacement steam generators' design and configuration did not provide the necessary margin to prevent fluid elastic instability and that these deficiencies appear to be related to MHI's thermal hydraulic code. The report further states that SCE is adequately pursuing the causes of the unexpected steam generator tube-to-tube degradation. The AIT report also identified a number of as-yet unresolved issues that are continuing to be examined. The unresolved issues include further evaluation of manufacturing differences between Unit 2 and Unit 3 with particular focus on the control of critical dimensions affecting the clearances between tubes and tube supports. The NRC will conduct subsequent inspections or reviews to determine what, if any, regulatory actions result from these unresolved items. Should the NRC find a deficiency in SCE's performance, SCE could be subject to additional regulatory action by the NRC, and the findings could be taken into consideration in the CPUC regulatory proceedings described below.
In March 2012, the NRC issued a Confirmatory Action Letter that required NRC permission to restart Unit 2 and Unit 3 and outlined actions SCE must complete before permission to restart either Unit may be sought. The NRC could also choose to impose additional inspections and assessment processes that could result in significant costs or additional delay. SCE is continuing to evaluate repairs and mitigation plans. Each Unit will only be restarted when the repairs and appropriate mitigation plans for that Unit are completed in accordance with the NRC's letter, and SCE is satisfied that it is safe to do so. Should SCE seek NRC approval to restart a Unit, the NRC may employ other procedures, including holding one or more public meetings, before making any determination about whether to grant permission pursuant to the terms of the Confirmatory Action Letter. It is also possible that one or more amendments to the NRC operating license for San Onofre might be required (whether or not as a prerequisite to return a Unit to safe operation). There is no set or predetermined time period for such processes, and, accordingly, there can be no assurance about the length of time the NRC may take to review any request to restart submitted by SCE under the Confirmatory Action Letter or whether any such request would be granted in whole or in part.
CPUC Review
In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million after adjustment for inflation) for SCE's 78.21% share of San Onofre to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $593 million through June 30, 2012 on the steam generator replacement project. Those expenditures remain subject to CPUC reasonableness review upon submission of SCE's final costs for the overall project.
As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre are being purchased in the market by SCE on behalf of customers (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market costs through June 30, 2012 were approximately $117 million, net of avoided nuclear fuel costs, and are recoverable through the ERRA balancing account subject to CPUC reasonableness review. Because of the uncertainties associated with when and at what output levels the Units will or may be returned to service, total potential market power costs cannot be estimated at this time. Costs for power are likely to be higher during the summer months.
Through June 2012, SCE's share of incremental inspection and repair costs totaled $48 million for both Units. Subject to NRC review under the Confirmatory Action Letter and any new developments that may result from further analysis, testing and inspection, SCE's share of further incremental costs to commence start-up of Unit 2 at the reduced power levels described above are expected to be approximately $25 million, although there is no assurance that start-up of Unit 2 will occur as described above. SCE's estimated share of the total incremental repair costs associated with returning Unit 3 to service, and returning both Units to service at originally specified capabilities safely, remain uncertain.
SCE's 2012 annual revenue requirement request for its direct operating and maintenance costs, depreciation and return on its investment in San Onofre Unit 2, Unit 3 and related common plant is approximately $650 million. At June 30, 2012, San Onofre rate base was $1.2 billion and the net investment and related inventory associated with San Onofre was $2.0 billion. Under California Public Utilities Code Section 455.5, SCE will be required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months, or November 2012 for Unit 3 and December 2012 for Unit 2 (not
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including preplanned outages). In that event, the CPUC is required within 45 days of SCE's notice for a particular Unit to initiate an investigation to determine whether to remove from customer rates some or all of the revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such rates are collected subject to refund. Under Section 455.5 any determination to adjust rates is made after hearings are conducted in connection with the utility's next general rate case. If, after investigation and hearings, the costs associated with a Unit are disallowed recovery because it is out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation. Notwithstanding the requirements of Section 455.5, the CPUC may institute other proceedings relating to the impact of the extended outage at San Onofre and its potential effects on rates, and there is currently pending before the CPUC a proposal to initiate an Order Instituting Investigation regarding such impacts.
Contractual Matters
The steam generators were designed and supplied by MHI and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. SCE's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $137 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions.
San Onofre carries both property damage and outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of potential claims for loss recovery. The property damage policy (including excess coverage) provides insurance for certain costs and expenses resulting from “Accidental Property Damage” with a $2.5 million deductible and a $2.75 billion limit of liability. After a twelve week deductible period, the outage policy provides insurance for an outage caused by “Accidental Property Damage” of up to $3.5 million per week for each Unit (or $2.8 million per Unit per week if both Units are out because of the same "Accident"), with a $490 million limit for each Unit ($392 million each if both Units are out because of the same "Accident"). The NEIL policies have a number of exclusions and limitations that may reduce or eliminate coverage. For instance, coverage may be reduced or excluded if it is determined that the outage resulted from any condition which develops, progresses or changes over time, or from wear and tear. Further, costs to "make good" faulty workmanship or design and amounts collectible from third parties are potentially excluded from the property damage policy. Proof of loss must be submitted within 12 months of the Accidental Property Damage under the property damage insurance and within 12 months of the end of the outage under the outage policy. For further information, see "Southern California Edison Company Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
SCE will pursue recoveries arising from available agreements, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements.
Capital Program
During the first six months of 2012, SCE's capital investment program focused on maintaining reliability and expanding the capability of SCE's transmission and distribution system; upgrading and constructing new transmission lines and substations; installing digital meters; and replacing generation asset equipment. Total capital expenditures (including accruals) were $1.73 billion during the first six months of 2012 compared to $1.6 billion during the same period in 2011. SCE expects that 2012 capital expenditures will be at or below the lower end of the previously projected $4.4 billion to $5.0 billion range due to the delay in the GRC decision, the delay related to the Tehachapi Project and resolution of the San Onofre issues. However, SCE continues to project that 2012 – 2014 total capital expenditures will be in the range of $11.8 billion to $13.2 billion. Actual capital spending will be affected by: changes in regulatory, environmental and engineering design requirements; permitting and project delays; cost and availability of labor, equipment and materials; outcome of the San Onofre mitigation plans; and other factors.
Environmental Developments
For a discussion of environmental developments, see "SCE Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
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RESULTS OF OPERATIONS
SCE's results of operations are derived mainly through two sources:
• | Utility earning activities – representing revenue authorized by the CPUC and FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of authorized operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in utility earnings activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any. |
• | Utility cost-recovery activities – representing CPUC- and FERC-authorized balancing accounts which allow for recovery of specific project or program costs, subject to reasonableness review or compliance with upfront standards. |
The following tables summarize SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities. Beginning in 2012, SCE classified revenues and costs related to programs that provide for recovery of actual costs plus a return on capital as utility earning activities. Previously, SCE classified the recovery of actual costs incurred under these programs as utility cost-recovery activities. The tables presented below reflect a reclassification of the revenues and costs for 2011 consistent with the presentation in 2012. The reclassification of revenues and costs had no impact on earnings.
During the first six months of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement included in customer rates. A GRC memorandum account has been established for SCE, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012. Recognition of the revenue for the period January 1, 2012 through the date of a final decision, as well as any delays in certain expenditures and changes in authorized treatment of specific costs, will impact the timing of earnings in 2012 (see "Management Overview—2012 CPUC General Rate Case" for further discussion).
Three Months Ended June 30, 2012 versus June 30, 2011
Three months ended June 30, 2012 | Three months ended June 30, 2011 | |||||||||||||||||
(in millions) | Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | ||||||||||||
Operating revenue | $ | 1,460 | $ | 1,191 | $ | 2,651 | $ | 1,432 | $ | 1,014 | $ | 2,446 | ||||||
Fuel and purchased power | — | 883 | 883 | — | 732 | 732 | ||||||||||||
Operations and maintenance | 564 | 302 | 866 | 565 | 281 | 846 | ||||||||||||
Depreciation decommissioning and amortization | 399 | — | 399 | 356 | — | 356 | ||||||||||||
Property taxes and other | 72 | 1 | 73 | 68 | 1 | 69 | ||||||||||||
Total operating expenses | 1,035 | 1,186 | 2,221 | 989 | 1,014 | 2,003 | ||||||||||||
Operating income | 425 | 5 | 430 | 443 | — | 443 | ||||||||||||
Net interest expense and other | (103 | ) | (5 | ) | (108 | ) | (89 | ) | — | (89 | ) | |||||||
Income before income taxes | 322 | — | 322 | 354 | — | 354 | ||||||||||||
Income tax expense | 108 | — | 108 | 128 | — | 128 | ||||||||||||
Net income | 214 | — | 214 | 226 | — | 226 | ||||||||||||
Dividends on preferred and preference stock | 23 | — | 23 | 15 | — | 15 | ||||||||||||
Net income available for common stock | $ | 191 | $ | — | $ | 191 | $ | 211 | $ | — | $ | 211 | ||||||
Core Earnings1 | $ | 191 | $ | 211 | ||||||||||||||
Non-Core Earnings | — | — | ||||||||||||||||
Total SCE GAAP Earnings | $ | 191 | $ | 211 | ||||||||||||||
1 | See use of Non-GAAP financial measures in "Management Overview—Highlights of Operating Results." |
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Utility Earning Activities
Utility earning activities were primarily affected by the following:
• | Higher operating revenue of $28 million, primarily due to: |
• | $20 million increase primarily due to revenue related to authorized CPUC projects not included in SCE's GRC process including the EdisonSmartConnect® project and the Solar Photovoltaic project. |
• | Operations and maintenance expense reflects $29 million of costs related to the steam generator inspection and repair at San Onofre (see "Management Overview—San Onofre Outage, Inspection and Repair Issues" for further information) offset by EdisonSmartConnect® benefits realized and other cost savings and timing of expenses. |
• | Higher depreciation, decommissioning and amortization expense of $43 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs. |
• | Higher net interest expense and other of $14 million was primarily due to higher outstanding balances on long-term debt. For details of other income and expenses, see "SCE Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses." |
• | Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information. |
• | Higher preferred and preference stock dividends of $8 million related to new issuances in 2012. |
Utility Cost-Recovery Activities
Utility cost-recovery activities were primarily affected by the following:
• | Higher fuel and purchased power expense of $151 million was primarily driven by $83 million of market costs net of lower nuclear fuel costs related to the outage at San Onofre in 2012 (see "Management Overview—San Onofre Outage, Inspection and Repair Issues" for further information). The increase was also due to the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below). These increases were partially offset by lower power prices in 2012. |
• | Higher operations and maintenance expense of $21 million was primarily due to increased pension contributions partially offset by lower transmission access charges. |
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Six Months Ended June 30, 2012 versus June 30, 2011
Six months ended June 30, 2012 | Six months ended June 30, 2011 | |||||||||||||||||
(in millions) | Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | ||||||||||||
Operating revenue | $ | 2,916 | $ | 2,147 | $ | 5,063 | $ | 2,837 | $ | 1,841 | $ | 4,678 | ||||||
Fuel and purchased power | — | 1,575 | 1,575 | — | 1,317 | 1,317 | ||||||||||||
Operations and maintenance | 1,151 | 566 | 1,717 | 1,108 | 523 | 1,631 | ||||||||||||
Depreciation decommissioning and amortization | 788 | — | 788 | 700 | — | 700 | ||||||||||||
Property taxes and other | 155 | 1 | 156 | 145 | 1 | 146 | ||||||||||||
Total operating expenses | 2,094 | 2,142 | 4,236 | 1,953 | 1,841 | 3,794 | ||||||||||||
Operating income | 822 | 5 | 827 | 884 | — | 884 | ||||||||||||
Net interest expense and other | (200 | ) | (5 | ) | (205 | ) | (171 | ) | — | (171 | ) | |||||||
Income before income taxes | 622 | — | 622 | 713 | — | 713 | ||||||||||||
Income tax expense | 208 | — | 208 | 251 | — | 251 | ||||||||||||
Net income | 414 | — | 414 | 462 | — | 462 | ||||||||||||
Dividends on preferred and preference stock | 41 | — | 41 | 29 | — | 29 | ||||||||||||
Net income available for common stock | $ | 373 | $ | — | $ | 373 | $ | 433 | $ | — | $ | 433 | ||||||
Core Earnings1 | $ | 373 | $ | 433 | ||||||||||||||
Non-Core Earnings | — | — | ||||||||||||||||
Total SCE GAAP Earnings | $ | 373 | $ | 433 | ||||||||||||||
1 | See use of Non-GAAP financial measures in "Management Overview—Highlights of Operating Results." |
Utility Earning Activities
Utility earning activities were primarily affected by the following:
• | SCE had higher operating revenue of $79 million, primarily due to the following: |
• | $60 million increase was primarily due to revenue related to authorized CPUC projects not included in SCE's GRC process including the EdisonSmartConnect® project and the Solar Photovoltaic project. |
• | Revenue recognized in 2012 related to the San Onofre Unit 2 scheduled outage costs. In December 2011, the CPUC authorized revenue requirements for 2012 refueling outages for San Onofre. |
• | Higher operation and maintenance expense of $43 million was primarily due to $48 million of costs related to the steam generator inspection and repair at San Onofre (see "Management Overview—San Onofre Outage, Inspection and Repair Issues" for further information) as well as $35 million related to the 2012 San Onofre Unit 2 scheduled maintenance and refueling outage. These increases were partially offset by EdisonSmartConnect® benefits realized and other cost savings and timing of expenses. |
• | Higher depreciation, decommissioning and amortization expense of $88 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs. |
• | Higher net interest expense and other of $29 million was primarily due to higher outstanding balances on long-term debt and a lower AFUDC capitalization rate in 2012 mainly driven by lower cost of financing resulting from an increase in the use of short-term debt. For details of other income and expenses, see "SCE Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses." |
• | Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information. |
• | Higher preferred and preference stock dividends of $12 million related to new issuances in 2012. |
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Utility Cost-Recovery Activities
Utility cost-recovery activities were primarily affected by the following:
• | Higher fuel and purchased power expense of $258 million was primarily driven by $117 million of market costs net of lower nuclear fuel costs related to the San Onofre outage in 2012 (see "Management Overview—San Onofre Outage, Inspection and Repair Issues" for further information). The increase was also due to the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below). These increases were partially offset by lower power prices in 2012. |
• | Higher operation and maintenance expense of $43 million was primarily due to increased pension contributions partially offset by lower spending for public purpose programs. |
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $2.7 billion and $5.0 billion for the three- and six-month periods ended June 30, 2012, respectively, compared to $2.4 billion and $4.5 billion for the respective periods in 2011. The increase in revenue reflects:
• | A sales volume increase of $417 million and $701 million for the three- and six-month periods, respectively, primarily due to SCE providing power that was previously provided by CDWR contracts which expired in 2011. Prior to 2012, SCE remitted to CDWR and did not recognize as revenue the amounts that SCE billed and collected from its customers for the portion of electric power purchased and sold by the CDWR to SCE's customers. |
• | A rate decrease of $110 million and $211 million for the three- and six-month periods, respectively, resulting from a rate adjustment beginning on June 1, 2011, primarily reflecting the refund to customers of overcollected fuel and power procurement-related costs. |
As a result of the CPUC-authorized decoupling mechanism, SCE earnings are not affected by changes in retail electricity sales (see "Item 1. Business—Overview of Ratemaking Process" in the 2011 Form 10-K).
Income Taxes
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(in millions) | 2012 | 2011 | 2012 | 2011 | |||||||||||
Income before income taxes | $ | 322 | $ | 354 | $ | 622 | $ | 713 | |||||||
Provision for income tax at federal statutory rate of 35% | 113 | 124 | 218 | 249 | |||||||||||
Increase (decrease) in income tax from: | |||||||||||||||
State tax – net of federal benefit | 10 | 18 | 20 | 30 | |||||||||||
Property-related | (10 | ) | (10 | ) | (20 | ) | (21 | ) | |||||||
Other | (5 | ) | (4 | ) | (10 | ) | (7 | ) | |||||||
Total income tax expense | $ | 108 | $ | 128 | $ | 208 | $ | 251 | |||||||
Effective tax rate | 33.5 | % | 36.2 | % | 33.4 | % | 35.2 | % | |||||||
For a discussion of the status of Edison International's income tax audits, see "SCE Notes to Consolidated Financial Statements—Note 7. Income Taxes."
LIQUIDITY AND CAPITAL RESOURCES
SCE's ability to operate its business, fund capital expenditures, and implement its business strategy are dependent upon its cash flow and access to the capital markets. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, interest and dividend payments to investors, and the outcome of tax and regulatory matters.
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SCE expects to fund its 2012 obligations, capital expenditures and dividends through operating cash flows and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities to meet operating and capital requirements.
Available Liquidity
During the second quarter of 2012, SCE replaced its existing credit facilities scheduled to mature in early 2013 with a new $2.75 billion five-year revolving credit facility that matures May 2017. The following table summarizes the status of the SCE credit facility at June 30, 2012:
(in millions) | Credit Facilities | ||
Commitment | $ | 2,750 | |
Outstanding commercial paper supported by credit facilities | (300 | ) | |
Outstanding letters of credit | (63 | ) | |
Amount available | $ | 2,387 | |
Debt Covenant
SCE has a debt covenant in its credit facility that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At June 30, 2012, SCE's debt to total capitalization ratio was 0.46 to 1.
Capital Investment Plan
Transmission Projects - Tehachapi Project
As discussed in the year-ended 2011 MD&A, the CPUC requested that SCE provide information on potential new options for a portion of the Tehachapi Project, including traversing a state park, changing the nature of some of the towers and undergrounding lines. In July 2012, the Assigned Commissioner issued a ruling requesting SCE to further study and provide more detailed information by the end of February 2013 on two identified undergrounding options for a portion of the project. The ruling set forth a schedule for interested parties to also provide further information, briefing by all parties and evidentiary hearings. The order states that the construction of the affected portion of the project shall remain deferred until the CPUC makes a final determination regarding the options. Adoption of either of the two undergrounding options could create additional costs and delay the completion of the project. SCE is required to file revised cost estimates with the CPUC. As with all transmission investments, cost recovery will be subject to future rate proceedings.
Regulatory Proceedings
FERC Formula Rates
As discussed in the year-ended 2011 MD&A, the FERC has accepted, subject to refund and settlement procedures, SCE's request to implement formula rates as a means to determine SCE's FERC transmission revenue requirement effective January 1, 2012. SCE's request would result in a total 2012 FERC weighted average ROE of 11.1% including a base ROE of 9.93% and the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives. The formula rate mechanism, including the base ROE, is subject to final resolution as part of the settlement process or, if a settlement is not achieved, to determination by FERC in a litigated process. SCE and the other parties to the proceeding continue to engage in settlement negotiations.
In June 2012, SCE provided its preliminary 2013 forecasted revenue requirement to interested parties. Consistent with SCE's proposed formula rate methodology, the application of the formula rate results in an increase in SCE's revenue requirement of $172 million, or 24%. The increase is primarily due to higher FERC rate base from transmission investments, including projects under construction. SCE expects to file its 2013 forecasted revenue requirement with the FERC by September 15, 2012, with the proposed rates effective from October 1, 2012 through September 30, 2013.
Dividend Restrictions
The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At June 30, 2012, SCE's 13-
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month weighted-average common equity component of total capitalization was 49.4% resulting in the capacity to pay $261 million in additional dividends to Edison International.
During the first six months of 2012, SCE made $233 million in dividend payments to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the level of capital expenditures, operating cash flows and earnings.
Margin and Collateral Deposits
Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. Future collateral requirements may differ from the requirements at June 30, 2012, due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, and the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations.
Some of the power procurement contracts contain provisions that require SCE to maintain an investment grade credit rating from the major credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral.
The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of June 30, 2012.
(in millions) | ||||
Collateral posted as of June 30, 20121 | $ | 154 | ||
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade | 128 | |||
Posted and potential collateral requirements2 | $ | 282 | ||
1 | Collateral provided to counterparties and other brokers consisted of $66 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $25 million of cash reflected in "Other current assets" on the consolidated balance sheets and $63 million in letters of credit. |
2 | There would be no increase to SCE's total posted and potential collateral requirements based on SCE's forward positions as of June 30, 2012 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level. |
Workers Compensation Self-Insurance Fund
For a discussion of potential collateral requirements related to its self-insured workers compensation plan, refer to "Liquidity and Capital Resources—Workers Compensation Self-Insurance Fund" in the year ended 2011 MD&A.
Historical Consolidated Cash Flows
The table below sets forth condensed historical cash flow information for SCE.
Six months ended June 30, | |||||||
(in millions) | 2012 | 2011 | |||||
Net cash provided by operating activities | $ | 1,511 | $ | 1,385 | |||
Net cash provided by financing activities | 712 | 491 | |||||
Net cash used by investing activities | (2,239 | ) | (2,091 | ) | |||
Net decrease in cash and cash equivalents | $ | (16 | ) | $ | (215 | ) | |
Net Cash Provided by Operating Activities
Net cash provided by operating activities increased $126 million in the first six months of 2012 compared to the same period in 2011. The increase in cash flows provided by operating activities was primarily due to the timing of cash receipts and disbursements related to working capital items, partially offset by lower net tax receipts in 2012.
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Net Cash Provided by Financing Activities
The following table summarizes cash provided by financing activities for the six months ended June 30, 2012 and 2011. Issuances of debt and preference stock are discussed in "SCE Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "Note 12. Preferred and Preference Stock."
Six months ended June 30, | |||||||
(in millions) | 2012 | 2011 | |||||
Issuances of first and refunding mortgage bonds, net | $ | 391 | $ | 492 | |||
Net issuances of commercial paper1 | (119 | ) | 200 | ||||
Issuances of preference stock, net | 805 | 123 | |||||
Payments of common stock dividends to Edison International | (233 | ) | (230 | ) | |||
Redemptions of preference stock | (75 | ) | — | ||||
Bonds purchased | — | (56 | ) | ||||
Payments of preferred and preference stock dividends | (28 | ) | (28 | ) | |||
Other | (29 | ) | (10 | ) | |||
Net cash provided by financing activities | $ | 712 | $ | 491 | |||
1 | Issuances of commercial paper are supported by SCE's credit facility. |
The timing and amount of SCE's financing activities are largely driven by its capital program.
Net Cash Used by Investing Activities
Cash flows from investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $2.1 billion and $2.0 billion for the six months ended June 30, 2012 and 2011, respectively (see "Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2011 MD&A for further information on capital expenditures). Net purchases of nuclear decommissioning trust investments and other were $125 million and $84 million for the six months ended June 30, 2012 and 2011, respectively.
Contractual Obligations and Contingencies
Contractual Obligations
SCE has power purchase commitments which are discussed in "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
Contingencies
SCE has contingencies related to the San Onofre Outage, Inspection and Repair Issues, CPSD Investigations, Four Corners New Source Review Litigation, Nuclear Insurance, Wildfire Insurance and Spent Nuclear Fuel, which are discussed in "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
Environmental Remediation
As of June 30, 2012, SCE had identified 25 material sites for remediation and recorded an estimated minimum liability of $43 million. SCE expects to recover 90% of its remediation costs at certain sites. See "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies" for further discussion.
MARKET RISK EXPOSURES
SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. Derivative instruments are used, as appropriate, to manage market risks for customers and SCE. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "SCE Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities" and "—Note 4. Fair Value Measurements."
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Commodity Price Risk
The fair value of outstanding derivative instruments used to mitigate SCE's exposure to commodity price risk was a net liability of $865 million and $936 million at June 30, 2012 and December 31, 2011, respectively. To the extent San Onofre Unit 2 and Unit 3 are not operating, SCE may be exposed to market prices associated with replacement power costs. SCE's hedging program has taken this exposure into consideration and has entered into forward contracts to address projected market price variability. For further discussion of fair value measurements and the fair value hierarchy, see "SCE Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."
Credit Risk
Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. As of June 30, 2012, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:
June 30, 2012 | |||||||||||
(in millions) | Exposure2 | Collateral | Net Exposure | ||||||||
S&P Credit Rating1 | |||||||||||
A or higher | $ | 95 | $ | — | $ | 95 | |||||
BBB | 2 | — | 2 | ||||||||
BBB- | 1 | — | 1 | ||||||||
Not rated3 | 3 | (3 | ) | — | |||||||
Total | $ | 101 | $ | (3 | ) | $ | 98 | ||||
1 | SCE assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings. |
2 | Exposure excludes amounts related to contracts classified as normal purchases and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related net accounts receivable. |
3 | The exposure in this category relates to long-term power purchase agreements. SCE's exposure is mitigated by regulatory treatment. |
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
For a discussion of SCE's critical accounting estimates and policies, see "Critical Accounting Estimates and Policies" in the year ended 2011 MD&A.
NEW ACCOUNTING GUIDANCE
New accounting guidance is discussed in "SCE Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to this item is included in the MD&A under the heading "Market Risk Exposures" and is incorporated herein by reference.
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ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
SCE's management, under the supervision and with the participation of the company's President and Chief Financial Officer, has evaluated the effectiveness of SCE's disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the second quarter of 2012. Based on that evaluation, the President and Chief Financial Officer concluded that, as of the end of the second quarter of 2012, SCE's disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
There were no changes in SCE's internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the second quarter of 2012 that have materially affected, or are reasonably likely to materially affect, SCE's internal control over financial reporting.
Jointly Owned Utility Plant
SCE's scope of evaluation of internal control over financial reporting includes its Jointly Owned Utility Projects.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table contains information about all purchases of Southern California Edison Series A Preference Stock made by or on behalf of Southern California Edison in the second quarter of 2012.
Period | (a) Total Number of Shares (or Units) Purchased1 | (b) Average Price Paid per Share (or Unit)1 | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs | ||||||
April 1, 2012 to April 30, 2012 | — | — | ||||||||
May 1, 2012 to May 30, 2012 | — | — | ||||||||
June 1, 2012 to June 30, 2012 | 750,000 | $ | 100.00 | 750,000 | — | |||||
Total | 750,000 | $ | 100.00 | 750,000 | — | |||||
1 | On June 16, 2012, SCE repurchased 750,000 shares ($75 million principal amount) of the Series A Preference Shares at $100 (liquidation value) per share. This partial redemption of SCE's Series A Preference Stock was announced via an SCE press release on May 17, 2012. |
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ITEM 6. EXHIBITS
Exhibit Number | Description | |
3.1 | Bylaws of Southern California Edison Company, as amended June 21, 2012 (File 1-2313, filed as Exhibit 3.1 to Southern California Edison Company's Form 8-K dated June 21, 2012 and filed June 22, 2012)* | |
10.1 | Credit Agreement dated as of May 18, 2012 among Southern California Edison Company and the Lenders named therein (File 1-2313, filed as Exhibit 10 to Southern California Edison Company's Form 8-K dated May 18, 2012 and filed May 24, 2012)* | |
10.2** | Edison International and Southern California Edison Company Director Compensation Schedule, as adopted June 21, 2012 (File 1-9936, filed as Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended June 30, 2012)* | |
31.1 | Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act | |
31.2 | Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act | |
32 | Statement Pursuant to 18 U.S.C. Section 1350 | |
101 | Financial statements from the quarterly report on Form 10-Q of Southern California Edison Company for the quarter ended June 30, 2012, filed on July 31, 2012, formatted in XBRL: (i) the Consolidated Statements of Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to Consolidated Financial Statements | |
_____________________________
* Incorporated by reference pursuant to Rule 12b-32.
** Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)3.
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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY | ||
By: | /s/ Chris C. Dominski | |
Chris C. Dominski Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer) | ||
Date: July 31, 2012
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