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TABLE OF CONTENTS
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) | ||
ý |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
|
For the quarterly period ended June 30, 2011 |
||
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 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
California | 95-4137452 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
|
2244 Walnut Grove Avenue (P. O. Box 976) Rosemead, California |
91770 |
|
(Address of principal executive offices) | (Zip Code) | |
(626) 302-2222 (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 ý 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 ý 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 ý | Accelerated filer o | Non-accelerated filer o (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 ý
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 August 1, 2011 | |
---|---|---|
Common Stock, no par value | 325,811,206 |
i
ii
iii
iv
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
2010 Form 10-K | Edison International's Annual Report on Form 10-K for the year-ended December 31, 2010 | |
2010 Tax Relief Act | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 |
|
AFUDC | allowance for funds used during construction | |
Ambit project | American Bituminous Power Partners, L.P. | |
AOI | Adjusted Operating Income (Loss) | |
APS | Arizona Public Service Company | |
ARO(s) | asset retirement obligation(s) | |
BACT | best available control technology | |
BART | best available retrofit technology | |
Bcf | billion cubic feet | |
Big 4 | Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects | |
Btu | British thermal units | |
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 | |
coal plants | Midwest Generation coal plants and Homer City plant | |
Commonwealth Edison | Commonwealth Edison Company | |
CPS | Combined Pollutant Standard | |
CPUC | California Public Utilities Commission | |
CSAPR | Cross-State Air Pollution Rule | |
CRRs | congestion revenue rights | |
DOE | U.S. Department of Energy | |
EME | Edison Mission Energy | |
EMG | Edison Mission Group Inc. | |
EMMT | Edison Mission Marketing & Trading, Inc. | |
EPS | earnings per share | |
ERRA | energy resource recovery account | |
EWG | Exempt Wholesale Generator | |
Exelon Generation | Exelon Generation Company LLC | |
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 resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002 and related matters with state tax authorities. | |
GRC | general rate case | |
GWh | gigawatt-hours | |
Homer City | EME Homer City Generation L.P., a Pennsylvania limited partnership that leases and operates three coal-fired electric generating units and related facilities located in Indiana County, Pennsylvania |
v
Illinois EPA | Illinois Environmental Protection Agency | |
IRS | Internal Revenue Service | |
ISO | Independent System Operator | |
kWh(s) | kilowatt-hour(s) | |
LIBOR | London Interbank Offered Rate | |
MD&A | Management's Discussion and Analysis of Financial Condition and Results of Operations in this report |
|
Midwest Generation | Midwest Generation, LLC | |
Midwest Generation plants | EME's power plants (fossil fuel) located in Illinois | |
MMBtu | million British thermal units | |
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 and Technology Upgrade | |
MW | megawatts | |
MWh | megawatt-hours | |
NAAQS | national ambient air quality standards | |
NAPP | Northern Appalachian | |
NERC | North American Electric Reliability Corporation | |
Ninth Circuit | U.S. Court of Appeals for the Ninth Circuit | |
NOV | notice of violation | |
NOx | nitrogen oxide | |
NRC | Nuclear Regulatory Commission | |
NSR | New Source Review | |
NYISO | New York Independent System Operator | |
PADEP | Pennsylvania Department of Environmental Protection | |
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 | |
PJM | PJM Interconnection, LLC | |
PRB | Powder River Basin | |
PSD | Prevention of Significant Deterioration | |
QF(s) | qualifying facility(ies) | |
ROE | return on equity | |
RPM | Reliability Pricing Model | |
RTO(s) | Regional Transmission Organization(s) | |
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 |
|
SCE | Southern California Edison Company | |
SNCR | selective non-catalytic reduction | |
SDG&E | San Diego Gas & Electric | |
SEC | U.S. Securities and Exchange Commission | |
SIP(s) | state implementation plan(s) | |
SO2 | sulfur dioxide | |
US EPA | U.S. Environmental Protection Agency | |
VIE(s) | variable interest entity(ies) | |
year-ended 2010 MD&A | Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in the 2010 Form 10-K |
|
vi
Consolidated Statements of Income |
Edison International |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||
(in millions, except per-share amounts, unaudited) |
2011 |
2010 |
2011 |
2010 |
|||||||||
Electric utility |
$ | 2,445 | $ | 2,246 | $ | 4,676 | $ | 4,405 | |||||
Competitive power generation |
538 | 495 | 1,090 | 1,147 | |||||||||
Total operating revenue |
2,983 | 2,741 | 5,766 | 5,552 | |||||||||
Fuel |
256 | 254 | 515 | 549 | |||||||||
Purchased power |
649 | 612 | 1,158 | 1,220 | |||||||||
Operations and maintenance |
1,263 | 1,144 | 2,412 | 2,183 | |||||||||
Depreciation, decommissioning and amortization |
435 | 380 | 852 | 749 | |||||||||
Total operating expenses |
2,603 | 2,390 | 4,937 | 4,701 | |||||||||
Operating income |
380 | 351 | 829 | 851 | |||||||||
Interest and dividend income |
30 | 4 | 34 | 23 | |||||||||
Equity in income from unconsolidated affiliates net |
18 | 20 | 12 | 39 | |||||||||
Other income |
42 | 36 | 83 | 70 | |||||||||
Interest expense |
(203 | ) | (175 | ) | (398 | ) | (343 | ) | |||||
Other expenses |
(13 | ) | (16 | ) | (25 | ) | (28 | ) | |||||
Income from continuing operations before income taxes |
254 | 220 | 535 | 612 | |||||||||
Income tax expense (benefit) |
62 | (136 | ) | 127 | 14 | ||||||||
Income from continuing operations |
192 | 356 | 408 | 598 | |||||||||
Income (loss) from discontinued operations net of tax |
(1 | ) | 1 | (3 | ) | 8 | |||||||
Net income |
191 | 357 | 405 | 606 | |||||||||
Dividends on preferred and preference stock of utility |
15 | 13 | 29 | 26 | |||||||||
Net income attributable to Edison International common shareholders |
$ | 176 | $ | 344 | $ | 376 | $ | 580 | |||||
Amounts attributable to Edison International common shareholders: |
|||||||||||||
Income from continuing operations, net of tax |
$ | 177 | $ | 343 | $ | 379 | $ | 572 | |||||
Income (loss) from discontinued operations, net of tax |
(1 | ) | 1 | (3 | ) | 8 | |||||||
Net income attributable to Edison International common shareholders |
$ | 176 | $ | 344 | $ | 376 | $ | 580 | |||||
Basic earnings per common share attributable to Edison International common shareholders: |
|||||||||||||
Weighted-average shares of common stock outstanding |
326 | 326 | 326 | 326 | |||||||||
Continuing operations |
$ | 0.54 | $ | 1.05 | $ | 1.16 | $ | 1.75 | |||||
Discontinued operations |
| | (0.01 | ) | 0.02 | ||||||||
Total |
$ | 0.54 | $ | 1.05 | $ | 1.15 | $ | 1.77 | |||||
Diluted earnings per common share attributable to Edison International common shareholders: |
|||||||||||||
Weighted-average shares of common stock outstanding, including effect of dilutive securities |
329 | 327 | 328 | 327 | |||||||||
Continuing operations |
$ | 0.54 | $ | 1.05 | $ | 1.16 | $ | 1.75 | |||||
Discontinued operations |
| | (0.01 | ) | 0.02 | ||||||||
Total |
$ | 0.54 | $ | 1.05 | $ | 1.15 | $ | 1.77 | |||||
Dividends declared per common share |
$ | 0.320 | $ | 0.315 | $ | 0.640 | $ | 0.630 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
1
Consolidated Statements of Comprehensive Income |
Edison International |
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|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||||
(in millions, unaudited) |
2011 |
2010 |
2011 |
2010 |
|||||||||||
Net income |
$ | 191 | $ | 357 | $ | 405 | $ | 606 | |||||||
Other comprehensive loss, net of tax: |
|||||||||||||||
Pension and postretirement benefits other than pensions: |
|||||||||||||||
Net gain arising during the period, net of income tax expense of $2 for the six months ended June 30, 2010 |
| | | 12 | |||||||||||
Amortization of net (gain) loss included in net income, net of income tax expense (benefit) of $1 and $1 for the three months and $3 and $(4) for the six months ended June 30, 2011 and 2010, respectively |
1 | 2 | 4 | (6 | ) | ||||||||||
Prior service credit arising during the period, net of income tax expense of $1 for the six months ended June 30, 2010 |
| | | 2 | |||||||||||
Amortization of prior service credit, net of income tax benefit of $1 for the six months ended June 30, 2010 |
| | | (2 | ) | ||||||||||
Unrealized gain (loss) on derivatives qualified as cash flow hedges: |
|||||||||||||||
Unrealized holding gain (loss) arising during the period, net of income tax expense (benefit) of $(9) and $(50) for the three months and $(5) and $12 for the six months ended June 30, 2011 and 2010, respectively |
(14 | ) | (77 | ) | (8 | ) | 18 | ||||||||
Reclassification adjustments included in net income, net of income tax benefit of $6 and $35 for the three months and $12 and $49 for the six months ended June 30, 2011 and 2010, respectively |
(7 | ) | (53 | ) | (17 | ) | (73 | ) | |||||||
Other comprehensive loss |
(20 | ) | (128 | ) | (21 | ) | (49 | ) | |||||||
Comprehensive income |
171 | 229 | 384 | 557 | |||||||||||
Less: Comprehensive income attributable to noncontrolling interests |
15 | 13 | 29 | 26 | |||||||||||
Comprehensive income attributable to Edison International |
$ | 156 | $ | 216 | $ | 355 | $ | 531 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
2
Consolidated Balance Sheets |
Edison International |
||||||
---|---|---|---|---|---|---|---|
(in millions, unaudited) |
June 30, 2011 |
December 31, 2010 |
|||||
ASSETS |
|||||||
Cash and cash equivalents |
$ | 945 | $ | 1,389 | |||
Receivables, less allowances of $87 and $85 for uncollectible accounts at respective dates |
1,018 | 931 | |||||
Accrued unbilled revenue |
619 | 442 | |||||
Inventory |
589 | 568 | |||||
Prepaid taxes |
356 | 390 | |||||
Derivative assets |
117 | 133 | |||||
Restricted cash |
11 | 2 | |||||
Margin and collateral deposits |
65 | 65 | |||||
Regulatory assets |
469 | 378 | |||||
Other current assets |
148 | 124 | |||||
Total current assets |
4,337 | 4,422 | |||||
Nuclear decommissioning trusts |
3,657 | 3,480 | |||||
Investments in unconsolidated affiliates |
552 | 559 | |||||
Other investments |
231 | 223 | |||||
Total investments |
4,440 | 4,262 | |||||
Utility property, plant and equipment, less accumulated depreciation of $6,486 and $6,319 at respective dates |
25,847 | 24,778 | |||||
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $2,009 and $1,865 at respective dates |
5,613 | 5,406 | |||||
Total property, plant and equipment |
31,460 | 30,184 | |||||
Derivative assets |
242 | 437 | |||||
Restricted deposits |
27 | 47 | |||||
Rent payments in excess of levelized rent expense under plant operating leases |
1,288 | 1,187 | |||||
Regulatory assets |
4,690 | 4,347 | |||||
Other long-term assets |
591 | 644 | |||||
Total long-term assets |
6,838 | 6,662 | |||||
|
|||||||
|
|||||||
|
|||||||
Total assets |
$ |
47,075 |
$ |
45,530 |
|||
The accompanying notes are an integral part of these consolidated financial statements.
3
Edison International |
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---|---|---|---|---|---|---|---|
Consolidated Balance Sheets |
|
|
|||||
(in millions, except share amounts, unaudited) |
June 30, 2011 |
December 31, 2010 |
|||||
LIABILITIES AND EQUITY |
|||||||
Short-term debt |
$ | 388 | $ | 115 | |||
Current portion of long-term debt |
53 | 48 | |||||
Accounts payable |
1,110 | 1,362 | |||||
Accrued taxes |
33 | 52 | |||||
Accrued interest |
225 | 205 | |||||
Customer deposits |
208 | 217 | |||||
Derivative liabilities |
238 | 217 | |||||
Regulatory liabilities |
820 | 738 | |||||
Other current liabilities |
807 | 998 | |||||
Total current liabilities |
3,882 | 3,952 | |||||
Long-term debt |
12,956 | 12,371 | |||||
Deferred income taxes |
5,819 | 5,625 | |||||
Deferred investment tax credits |
132 | 122 | |||||
Customer advances |
121 | 112 | |||||
Derivative liabilities |
580 | 468 | |||||
Pensions and benefits |
2,306 | 2,260 | |||||
Asset retirement obligations |
2,616 | 2,561 | |||||
Regulatory liabilities |
4,759 | 4,524 | |||||
Other deferred credits and other long-term liabilities |
2,147 | 2,041 | |||||
Total deferred credits and other liabilities |
18,480 | 17,713 | |||||
Total liabilities |
35,318 | 34,036 | |||||
Commitments and contingencies (Note 9) |
|||||||
Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at each date) |
2,347 | 2,331 | |||||
Accumulated other comprehensive loss |
(97 | ) | (76 | ) | |||
Retained earnings |
8,476 | 8,328 | |||||
Total Edison International's common shareholders' equity |
10,726 | 10,583 | |||||
Preferred and preference stock of utility |
1,029 | 907 | |||||
Other noncontrolling interests |
2 | 4 | |||||
Total noncontrolling interests |
1,031 | 911 | |||||
Total equity |
11,757 | 11,494 | |||||
Total liabilities and equity |
$ | 47,075 | $ | 45,530 | |||
The accompanying notes are an integral part of these consolidated financial statements.
4
Consolidated Statements of Cash Flows |
Edison International |
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---|---|---|---|---|---|---|---|---|
|
Six months ended June 30, |
|||||||
(in millions, unaudited) |
2011 |
2010 |
||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 405 | $ | 606 | ||||
Less: Income (loss) from discontinued operations |
(3 | ) | 8 | |||||
Income from continuing operations |
408 | 598 | ||||||
Adjustments to reconcile to net cash provided by operating activities: |
||||||||
Depreciation, decommissioning and amortization |
852 | 749 | ||||||
Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation) |
75 | 74 | ||||||
Other amortization |
75 | 56 | ||||||
Stock-based compensation |
15 | 14 | ||||||
Equity in income from unconsolidated affiliates net |
(12 | ) | (39 | ) | ||||
Distributions from unconsolidated entities |
15 | 39 | ||||||
Deferred income taxes and investment tax credits |
223 | 247 | ||||||
Proceeds from U.S. treasury grants |
| 92 | ||||||
Income from leveraged leases |
(3 | ) | (2 | ) | ||||
Changes in operating assets and liabilities: |
||||||||
Receivables |
64 | 13 | ||||||
Inventory |
(21 | ) | (36 | ) | ||||
Margin and collateral deposits net of collateral received |
1 | 12 | ||||||
Prepaid taxes |
34 | (167 | ) | |||||
Other current assets |
(189 | ) | (136 | ) | ||||
Rent payments in excess of levelized rent expense |
(101 | ) | (111 | ) | ||||
Accounts payable |
66 | (114 | ) | |||||
Accrued taxes |
(19 | ) | (69 | ) | ||||
Other current liabilities |
(212 | ) | (164 | ) | ||||
Derivative assets and liabilities net |
303 | 806 | ||||||
Regulatory assets and liabilities net |
(260 | ) | (720 | ) | ||||
Other assets |
(31 | ) | (36 | ) | ||||
Other liabilities |
(58 | ) | (152 | ) | ||||
Operating cash flows from discontinued operations |
(3 | ) | 8 | |||||
Net cash provided by operating activities |
1,222 | 962 | ||||||
Cash flows from financing activities: |
||||||||
Long-term debt issued |
592 | 645 | ||||||
Long-term debt issuance costs |
(5 | ) | (19 | ) | ||||
Long-term debt repaid |
(30 | ) | (366 | ) | ||||
Bonds purchased |
(56 | ) | | |||||
Preference stock issued net |
123 | | ||||||
Short-term debt financing net |
292 | 410 | ||||||
Settlements of stock-based compensation net |
(13 | ) | (2 | ) | ||||
Dividends and distributions to noncontrolling interests |
(28 | ) | (25 | ) | ||||
Dividends paid |
(209 | ) | (205 | ) | ||||
Net cash provided by financing activities |
$ | 666 | $ | 438 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
5
Edison International |
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---|---|---|---|---|---|---|---|
Consolidated Statements of Cash Flows |
|
|
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|
Six months ended June 30, |
||||||
(in millions, unaudited) |
2011 |
2010 |
|||||
Cash flows from investing activities: |
|||||||
Capital expenditures |
$ | (2,256 | ) | $ | (2,070 | ) | |
Purchase of interest in acquired companies |
| (4 | ) | ||||
Proceeds from sale of nuclear decommissioning trust investments |
1,146 | 600 | |||||
Purchases of nuclear decommissioning trust investments and other |
(1,230 | ) | (697 | ) | |||
Proceeds from partnerships and unconsolidated subsidiaries, net of investment |
5 | 44 | |||||
Investments in other assets |
3 | 13 | |||||
Effect of consolidation and deconsolidation of variable interest entities |
| (91 | ) | ||||
Net cash used by investing activities |
(2,332 | ) | (2,205 | ) | |||
Net decrease in cash and cash equivalents |
(444 | ) | (805 | ) | |||
Cash and cash equivalents, beginning of period |
1,389 | 1,673 | |||||
Cash and cash equivalents, end of period |
$ | 945 | $ | 868 | |||
The accompanying notes are an integral part of these consolidated financial statements.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1. Summary of Significant Accounting Policies
Edison International has two business segments for financial reporting purposes: an electric utility operation segment (SCE) and a competitive power generation segment (EMG). 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. EMG is the holding company for its principal wholly owned subsidiary, EME. EME is a holding company with subsidiaries and affiliates engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also engages in hedging and energy trading activities in competitive power markets through its Edison Mission Marketing & Trading, Inc. ("EMMT") subsidiary.
Basis of Presentation
Edison International's significant accounting policies were described in Note 1 of "Edison International Notes to Consolidated Financial Statements" included in the 2010 Form 10-K. Edison International follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2011, discussed below in "New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2010 Form 10-K.
In the opinion of management, all adjustments, including 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 ("GAAP") 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, 2011 are not necessarily indicative of the operating results for the full year.
The December 31, 2010 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.
Cash Equivalents
Cash equivalents included investments in money market funds totaling $743 million and $1.1 billion at June 30, 2011 and December 31, 2010, respectively. Generally, the carrying value of cash equivalents equals the fair value, as all investments have maturities of three months or less.
Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. Edison International reclassified $185 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at June 30, 2011 and December 31, 2010, respectively.
Inventory
Inventory is stated at the lower of cost or market, cost being determined by the weighted-average cost method for fuel, and the average cost method for materials and supplies. Inventory consisted of the following:
(in millions) |
June 30, 2011 |
December 31, 2010 |
|||||
---|---|---|---|---|---|---|---|
Coal, gas, fuel oil and other raw materials |
$ | 203 | $ | 184 | |||
Spare parts, materials and supplies |
386 | 384 | |||||
Total inventory |
$ | 589 | $ | 568 | |||
Earnings Per Share
Edison International computes earnings per share ("EPS") using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison
7
International's participating securities are stock-based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. EPS attributable to Edison International common shareholders was computed as follows:
|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
2011 |
2010 |
|||||||||
Basic earnings per share continuing operations: |
|||||||||||||
Income from continuing operations attributable to common shareholders, net of tax |
$ | 177 | $ | 343 | $ | 379 | $ | 572 | |||||
Participating securities dividends |
| (2 | ) | | (2 | ) | |||||||
Income from continuing operations available to common shareholders |
$ | 177 | $ | 341 | $ | 379 | $ | 570 | |||||
Weighted average common shares outstanding |
326 | 326 | 326 | 326 | |||||||||
Basic earnings per share continuing operations |
$ | 0.54 | $ | 1.05 | $ | 1.16 | $ | 1.75 | |||||
Diluted earnings per share continuing operations: |
|||||||||||||
Income from continuing operations available to common shareholders |
$ | 177 | $ | 341 | $ | 379 | $ | 570 | |||||
Income impact of assumed conversions |
1 | 1 | 1 | 1 | |||||||||
Income from continuing operations available to common shareholders and assumed conversions |
$ | 178 | $ | 342 | $ | 380 | $ | 571 | |||||
Weighted average common shares outstanding |
326 | 326 | 326 | 326 | |||||||||
Incremental shares from assumed conversions |
3 | 1 | 2 | 1 | |||||||||
Adjusted weighted average shares diluted |
329 | 327 | 328 | 327 | |||||||||
Diluted earnings per share continuing operations |
$ | 0.54 | $ | 1.05 | $ | 1.16 | $ | 1.75 | |||||
Stock-based compensation awards to purchase 5,896,940 and 9,645,334 shares of common stock for the three months ended June 30, 2011 and 2010, respectively, and 5,896,940 and 6,080,199 shares of common stock for the six months ended June 30, 2011 and 2010 respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares during the respective periods and, therefore, the effect would have been antidilutive.
New Accounting Guidance
Accounting Guidance Adopted in 2011
RevenueMultiple-Deliverables
In October 2009, the Financial Accounting Standards Board ("FASB") issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenues based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is required to be applied prospectively to new or significantly modified revenue arrangements. Edison International adopted this guidance effective January 1, 2011. The adoption of this accounting standards update did not have a material impact on Edison International's consolidated results of operations, financial position or cash flows.
Fair Value Measurements and Disclosures
The FASB issued an accounting standards update modifying the disclosure requirements related to fair value measurements. Under these requirements, purchases and settlements for Level 3 fair value measurements are presented on a gross basis, rather than net. Edison International adopted this guidance effective January 1, 2011.
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Accounting Guidance Not Yet Adopted
Fair Value Measurement
In May 2011, the 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 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. Edison International will adopt this guidance effective January 1, 2012 and does not expect the adoption of this standard will have a material impact on Edison International's consolidated statements of income, financial position or cash flows.
Presentation of Comprehensive Income
In June 2011, the FASB issued an accounting standards update 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. Edison International will adopt this guidance effective January 1, 2012. Edison International currently presents the statement of comprehensive income immediately following the statement of income and expects to continue to do so. The adoption of this accounting standards update does not change the items that constitute net income and other comprehensive income.
Note 2. Consolidated Statements of Changes in Equity
The following table provides the changes in equity for the six months ended June 30, 2011.
|
Equity Attributable to Edison International | Noncontrolling Interests | |
|||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Common Stock |
Accumulated Other Comprehensive Loss |
Retained Earnings |
Subtotal |
Other |
Preferred and Preference Stock |
Total Equity |
|||||||||||||||
Balance at December 31, 2010 |
$ | 2,331 | $ | (76 | ) | $ | 8,328 | $ | 10,583 | $ | 4 | $ | 907 | $ | 11,494 | |||||||
Net income |
| | 376 | 376 | | 29 | 405 | |||||||||||||||
Other comprehensive loss |
| (21 | ) | | (21 | ) | | | (21 | ) | ||||||||||||
Common stock dividends declared ($0.64 per share) |
| | (209 | ) | (209 | ) | | | (209 | ) | ||||||||||||
Dividends, distributions to noncontrolling interests and other |
| | | | (2 | ) | (29 | ) | (31 | ) | ||||||||||||
Stock-based compensation and other |
4 | | (17 | ) | (13 | ) | | | (13 | ) | ||||||||||||
Noncash stock-based compensation and other |
12 | | (2 | ) | 10 | | (1 | ) | 9 | |||||||||||||
Issuance of preference stock |
| | | | | 123 | 123 | |||||||||||||||
Balance at June 30, 2011 |
$ | 2,347 | $ | (97 | ) | $ | 8,476 | $ | 10,726 | $ | 2 | $ | 1,029 | $ | 11,757 | |||||||
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The following table provides the changes in equity for the six months ended June 30, 2010:
|
Equity Attributable to Edison International | Noncontrolling Interests | |
|||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Common Stock |
Accumulated Other Comprehensive Income |
Retained Earnings |
Subtotal |
Other |
Preferred and Preference Stock |
Total Equity |
|||||||||||||||
Balance at December 31, 2009 |
$ | 2,304 | $ | 37 | $ | 7,500 | $ | 9,841 | $ | 258 | $ | 907 | $ | 11,006 | ||||||||
Net income |
| | 580 | 580 | | 26 | 606 | |||||||||||||||
Other comprehensive loss |
| (49 | ) | | (49 | ) | | | (49 | ) | ||||||||||||
Deconsolidation of variable interest entities |
| | | | (249 | ) | | (249 | ) | |||||||||||||
Cumulative effect of a change in accounting principle, net of tax |
| | 15 | 15 | | | 15 | |||||||||||||||
Common stock dividends declared ($0.63 per share) |
| | (205 | ) | (205 | ) | | | (205 | ) | ||||||||||||
Dividends, distributions to noncontrolling interests and other |
| | | | (3 | ) | (26 | ) | (29 | ) | ||||||||||||
Stock-based compensation and other |
2 | | (4 | ) | (2 | ) | | | (2 | ) | ||||||||||||
Noncash stock-based compensation and other |
9 | | (7 | ) | 2 | | | 2 | ||||||||||||||
Balance at June 30, 2010 |
$ | 2,315 | $ | (12 | ) | $ | 7,879 | $ | 10,182 | $ | 6 | $ | 907 | $ | 11,095 | |||||||
Note 3. Variable Interest Entities
A variable interest entity ("VIE") is defined as a legal entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE. Commercial and operating activities are generally the factors that most significantly impact the economic performance of VIEs in which Edison International has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
Categories of Variable Interest Entities
Projects or Entities that are Consolidated
At June 30, 2011 and December 31, 2010, EMG consolidated 13 and 14 projects, respectively, with a total generating capacity of 570 MW and 580 MW, respectively, that have interests held by others. In April 2011, EMG sold its 75% ownership interest in a Minnesota wind project.
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The following table presents summarized financial information of the projects that were consolidated by EMG:
(in millions) |
June 30, 2011 |
December 31, 2010 |
||||||
---|---|---|---|---|---|---|---|---|
Current assets |
$ | 39 | $ | 26 | ||||
Net property, plant and equipment |
712 | 739 | ||||||
Other long-term assets |
5 | 6 | ||||||
Total assets |
$ | 756 | $ | 771 | ||||
Current liabilities |
$ | 23 | $ | 25 | ||||
Long-term debt net of current portion |
68 | 71 | ||||||
Deferred revenues |
69 | 71 | ||||||
Other long-term liabilities |
21 | 21 | ||||||
Total liabilities |
$ | 181 | $ | 188 | ||||
Noncontrolling interests |
$ |
3 |
$ |
4 |
||||
At June 30, 2011 and December 31, 2010, assets serving as collateral for the debt obligations had a carrying value of $163 million and primarily consist of property, plant and equipment.
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 operate 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 SCE's 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 under its 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, 2011 and the amounts that SCE paid to these projects were $83 million and $117 million for the three months ended June 30, 2011 and 2010, respectively, and $169 million and $242 million for the six months ended June 30, 2011 and 2010, respectively. These amounts are recovered in customer rates.
Equity Interests
EMG accounts for domestic gas and wind energy projects in which it has less than a 100% ownership interest, and cannot exercise unilateral control, under the equity method. At June 30, 2011 and December 31, 2010, EMG had five significant variable interests in natural gas projects that are not consolidated, consisting of the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson) and the Sunrise project. A subsidiary of EMG operates three of the four Big 4 projects and the Sunrise project and EMG's partner provides the fuel management services for the Big 4 projects. In addition, the executive director of these projects is provided by EMG's partner. Commercial and operating activities are jointly controlled by a management committee of each VIE. Accordingly, EMG accounts for its variable interests under the equity method.
At June 30, 2011 and December 31, 2010, EMG accounts for its interests in two renewable wind generating facilities, the Elkhorn Ridge and San Juan Mesa projects, under the equity method. In addition, EMG
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accounts for its interests in Community Wind North, which achieved commercial operation on May 28, 2011, under the equity method. The commercial and operating activities of these entities are jointly directed by representatives of each partner. Thus, EMG is not the primary beneficiary of these projects.
The following table presents the carrying amount of EMG's investments in unconsolidated VIEs and the maximum exposure to loss for each investment:
|
June 30, 2011 | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
Investment |
Maximum Exposure |
|||||
Natural gas-fired projects |
$ | 321 | $ | 321 | |||
Renewable energy projects |
229 | 229 | |||||
EMG's maximum exposure to loss in its VIEs accounted for under the equity method is generally limited to its investment in these entities. One of EMG's domestic energy projects has long-term debt that is secured by a pledge of project entity assets, but does not provide for recourse to EMG. Accordingly, a default under the project financing could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EMG's investment, but would not require EMG to contribute additional capital. At June 30, 2011, entities which EMG has accounted for under the equity method had indebtedness of $65 million, of which $16 million is proportionate to EMG's ownership interest in this project.
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 should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk.
Edison International categorizes financial assets and liabilities into a fair value hierarchy based on valuation inputs used to derive 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).
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The following table sets forth assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:
|
As of June 30, 2011 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Level 1 |
Level 2 |
Level 3 |
Netting and Collateral1 |
Total |
||||||||||||
Assets at Fair Value |
|||||||||||||||||
Money market funds2 |
$ | 743 | $ | | $ | | $ | | $ | 743 | |||||||
Derivative contracts: |
|||||||||||||||||
Electricity |
| 44 | 231 | (33 | ) | 242 | |||||||||||
Natural gas |
| 65 | 11 | | 76 | ||||||||||||
Fuel oil |
6 | | | (6 | ) | | |||||||||||
Tolling |
| | 41 | | 41 | ||||||||||||
Coal |
| 1 | | (1 | ) | | |||||||||||
Subtotal of commodity contracts |
6 | 110 | 283 | (40 | ) | 359 | |||||||||||
Long-term disability plan |
9 | | | | 9 | ||||||||||||
Nuclear decommissioning trusts: |
|||||||||||||||||
Stocks3 |
2,062 | | | | 2,062 | ||||||||||||
Municipal bonds |
| 812 | | | 812 | ||||||||||||
U.S. government and agency securities |
309 | 118 | | | 427 | ||||||||||||
Corporate bonds4 |
| 310 | | | 310 | ||||||||||||
Short-term investments, primarily cash equivalents5 |
4 | 31 | | | 35 | ||||||||||||
Subtotal of nuclear decommissioning trusts |
2,375 | 1,271 | | | 3,646 | ||||||||||||
Total assets6 |
3,133 | 1,381 | 283 | (40 | ) | 4,757 | |||||||||||
Liabilities at Fair Value |
|||||||||||||||||
Derivative contracts: |
|||||||||||||||||
Electricity |
| 9 | 71 | (9 | ) | 71 | |||||||||||
Natural gas |
| 239 | 6 | (1 | ) | 244 | |||||||||||
Tolling |
| | 481 | | 481 | ||||||||||||
Subtotal of commodity contracts |
| 248 | 558 | (10 | ) | 796 | |||||||||||
Interest rate contracts |
| 22 | | | 22 | ||||||||||||
Total liabilities |
| 270 | 558 | (10 | ) | 818 | |||||||||||
Net assets (liabilities) |
$ | 3,133 | $ | 1,111 | $ | (275 | ) | $ | (30 | ) | $ | 3,939 | |||||
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|
As of December 31, 2010 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Level 1 |
Level 2 |
Level 3 |
Netting and Collateral1 |
Total |
||||||||||||
Assets at Fair Value |
|||||||||||||||||
Money market funds2 |
$ | 1,100 | $ | | $ | | $ | | $ | 1,100 | |||||||
Derivative contracts: |
|||||||||||||||||
Electricity |
| 70 | 363 | (61 | ) | 372 | |||||||||||
Natural gas |
1 | 69 | 11 | (1 | ) | 80 | |||||||||||
Fuel oil |
8 | | | (8 | ) | | |||||||||||
Tolling |
| | 118 | | 118 | ||||||||||||
Subtotal of commodity contracts |
9 | 139 | 492 | (70 | ) | 570 | |||||||||||
Long-term disability plan |
9 | | | | 9 | ||||||||||||
Nuclear decommissioning trusts: |
|||||||||||||||||
Stocks3 |
2,029 | | | | 2,029 | ||||||||||||
Municipal bonds |
| 790 | | | 790 | ||||||||||||
Corporate bonds4 |
| 346 | | | 346 | ||||||||||||
U.S. government and agency securities |
215 | 73 | | | 288 | ||||||||||||
Short-term investments, primarily cash equivalents5 |
1 | 31 | | | 32 | ||||||||||||
Subtotal of nuclear decommissioning trusts |
2,245 | 1,240 | | | 3,485 | ||||||||||||
Total assets6 |
3,363 | 1,379 | 492 | (70 | ) | 5,164 | |||||||||||
Liabilities at Fair Value |
|||||||||||||||||
Derivative contracts: |
|||||||||||||||||
Electricity |
| 13 | 40 | (21 | ) | 32 | |||||||||||
Natural gas |
| 286 | 11 | (4 | ) | 293 | |||||||||||
Tolling |
| | 344 | | 344 | ||||||||||||
Coal |
| 1 | | (1 | ) | | |||||||||||
Subtotal of commodity contracts |
| 300 | 395 | (26 | ) | 669 | |||||||||||
Interest rate contracts |
| 16 | | | 16 | ||||||||||||
Total liabilities |
| 316 | 395 | (26 | ) | 685 | |||||||||||
Net assets (liabilities) |
$ | 3,363 | $ | 1,063 | $ | 97 | $ | (44 | ) | $ | 4,479 | ||||||
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The following table sets forth a summary of changes in the fair value of Level 3 assets and liabilities:
|
Three months ended June 30, |
Six months ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
2011 |
2010 |
||||||||||
Fair value, net asset (liabilities) at beginning of period |
$ | (44 | ) | $ | (397 | ) | $ | 97 | $ | 62 | ||||
Total realized/unrealized gains (losses): |
||||||||||||||
Included in earnings1 |
18 | (18 | ) | 18 | 27 | |||||||||
Included in regulatory assets and liabilities2 |
(247 | ) | (294 | ) | (382 | ) | (781 | ) | ||||||
Included in accumulated other comprehensive income |
(4 | ) | (2 | ) | (3 | ) | 4 | |||||||
Purchases |
22 | 26 | 28 | 32 | ||||||||||
Settlements |
(20 | ) | (24 | ) | (31 | ) | (52 | ) | ||||||
Transfers in or out of Level 3 |
| 6 | (2 | ) | 5 | |||||||||
Fair value, net liability at end of period |
$ | (275 | ) | $ | (703 | ) | $ | (275 | ) | $ | (703 | ) | ||
Change during the period in unrealized losses related to assets and liabilities held at the end of the period3 |
$ | (226 | ) | $ | (287 | ) | $ | (368 | ) | $ | (717 | ) | ||
Edison International determines the fair value for transfers in and transfers out of each level at the end of each reporting period. There were no significant transfers between levels during 2011 and 2010.
Valuation Techniques Used to Determine Fair Value
Level 1
Includes financial assets and liabilities where fair value is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. Financial assets and liabilities classified as Level 1 include exchange-traded equity securities, exchange traded derivatives, U.S. treasury securities and money market funds.
Level 2
Pricing inputs include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument. Financial assets and liabilities utilizing Level 2 inputs include fixed-income securities and over-the-counter derivatives.
Derivative contracts that are over-the-counter traded are valued using pricing models to determine the net present value of estimated future cash flows and are generally classified as Level 2. 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 source that best represents traded activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary 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. Broker quotes are incorporated when corroborated with other information which may include a combination of prices from exchanges, other brokers and comparison to executed trades.
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Level 3
Includes financial assets and liabilities where fair value is determined using techniques that require significant unobservable inputs. Over-the-counter options, bilateral contracts, capacity contracts, QF contracts, derivative contracts that trade infrequently (such as congestion revenue rights ("CRRs") in the California market), long-term power agreements, and derivative contracts with counterparties that have significant nonperformance risks are generally valued using pricing models that incorporate unobservable inputs and are classified as Level 3. Assumptions are made in order to value derivative contracts in which observable inputs are not available. In circumstances where Edison International cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, Edison International continues to assess valuation methodologies used to determine fair value.
For derivative contracts that trade infrequently (illiquid financial transmission rights and CRRs), changes in fair value are based on models forecasting the value of those contracts. The models' inputs are reviewed and the fair value is adjusted when it is concluded that a change in inputs would result in a new valuation that better reflects the fair value of those derivative contracts. For illiquid long-term power agreements, fair value is based upon the discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. The fair value of the majority of SCE's derivatives that are classified as Level 3 is determined using uncorroborated non-binding broker quotes and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness.
Nonperformance Risk
The fair value of the derivative assets and liabilities are adjusted for nonperformance risk. To assess nonperformance risks, SCE considers the probability of and the estimated loss incurred if a party to the transaction were to default. SCE also considers collateral, netting agreements, guarantees and other forms of credit support when assessing nonperformance. EMG reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of nonperformance. The nonperformance risk adjustment represented an insignificant amount at both June 30, 2011 and December 31, 2010.
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 amounts and fair values of long-term debt are:
|
June 30, 2011 | December 31, 2010 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
|||||||||
Long-term debt, including current portion |
$ | 13,009 | $ | 13,075 | $ | 12,419 | $ | 12,360 | |||||
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Fair values of long-term debt are 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, payables and short-term debt approximates fair value.
Note 5. Debt and Credit Agreements
Long-Term Debt
In May 2011, SCE issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.
In May 2011, SCE purchased $56 million of its tax-exempt bonds that were subject to remarketing and also converted these bonds to a variable rate structure. These bonds are held by SCE and remain outstanding and have not been retired or cancelled.
On July 27, 2011, EMG completed, through wholly owned subsidiaries, non-recourse financings to fund construction of the Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The financings included $122 million of letter of credit and working capital facilities, and also included floating rate construction loans totaling $495 million (with initial fundings of $48 million) that will convert to 10-year amortizing term loans by June 30, 2013, subject to meeting specified conditions.
As of July 27, 2011, EME entered into interest rate swap agreements and forward-starting interest rate swap agreements that converted the floating rate London Interbank Offered Rate ("LIBOR") construction loans to fixed rates. Under the interest rate swap agreements, EME will pay fixed rates of an average of 0.81% through May 31, 2013. Under the forward-starting swaps agreements, EME will pay an average fixed rate of 3.59% beginning June 30, 2013 through May 31, 2023. Interest under the project-level construction term loan of $442 million initially accrues at LIBOR plus 2.25% and increases by 0.25% after the third, sixth and ninth anniversaries. Interest on the intermediate holding company construction term loan of $53 million accrues at LIBOR plus 4.00% over the term.
Viento Funding II Wind Financing Amendment
In February 2011, EME completed, through its subsidiary, Viento Funding II, Inc., an amendment of its 2009 non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The amendment increased the financing amount to $255 million, which included a $227 million ten-year term loan (expiring in December 2020), a $23 million seven-year letter of credit facility and a $5 million seven-year working capital facility. At June 30, 2011, $216 million was outstanding under this loan. The amount of outstanding letters of credit was $23 million. Interest under the term loan accrues at LIBOR plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary.
Credit Agreements and Short-Term Debt
At June 30, 2011, SCE's outstanding short-term debt was $200 million at a weighted-average interest rate of 0.33%. This short-term debt was supported by a $2.4 billion credit facility. At December 31, 2010, there was no outstanding short-term debt. At June 30, 2011, letters of credit issued under SCE's credit facilities aggregated $71 million and are scheduled to expire in twelve months or less.
At June 30, 2011, Edison International (Parent)'s outstanding short-term debt was $79 million at a weighted-average interest rate of 0.55%. At December 31, 2010, the outstanding short-term debt was $19 million at a weighted-average interest rate of 0.63%.
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At June 30, 2011, standby letters of credit under EME's credit facility aggregated $116 million and were scheduled to expire as follows: $39 million in 2011 and $77 million in 2012. The aggregate amount includes $39 million of letters of credit issued for the benefit of SCE, which is the power purchase agreement counterparty for the Walnut Creek project. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $51 million, $3 million of which was under the Midwest Generation, LLC (Midwest Generation) credit facility, and were scheduled to expire as follows: $7 million in 2011, $16 million in 2012, $10 million in 2017, and $18 million in 2018. Certain letters of credit are subject to automatic annual renewal provisions.
Note 6. Derivative Instruments and Hedging Activities
Electric Utility
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 ratepayer 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 pre-approved by the California Public Utilities Commission ("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 electricity purchased from and sold to the California and other wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities, power purchase agreements and California Department of Water Resources ("CDWR") contracts allocated to SCE.
SCE's natural gas price exposure arises from natural gas purchased for generation at 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, 2011 |
December 31, 2010 |
||||||
Electricity options, swaps and forwards |
GWh | 34,471 | 32,138 | ||||||
Natural gas options, swaps and forwards |
Bcf | 255 | 250 | ||||||
CRRs |
GWh | 147,992 | 181,291 | ||||||
Tolling arrangements |
GWh | 105,631 | 114,599 | ||||||
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Fair Value of Derivative Instruments
The following table summarizes the gross and net fair values of commodity derivative instruments at June 30, 2011:
|
Derivative Assets | Derivative Liabilities | |
|||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Short- Term |
Long- Term |
Subtotal |
Short- Term |
Long- Term |
Subtotal |
Net Liability |
|||||||||||||||
Non-trading activities |
||||||||||||||||||||||
Economic hedges |
$ | 89 | $ | 200 | $ | 289 | $ | 243 | $ | 579 | $ | 822 | $ | 533 | ||||||||
Netting and collateral |
(11 | ) | (21 | ) | (32 | ) | (12 | ) | (21 | ) | (33 | ) | (1 | ) | ||||||||
Total |
$ | 78 | $ | 179 | $ | 257 | $ | 231 | $ | 558 | $ | 789 | $ | 532 | ||||||||
The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2010:
|
Derivative Assets | Derivative Liabilities | |
|||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Short- Term |
Long- Term |
Subtotal |
Short- Term |
Long- Term |
Subtotal |
Net Liability |
|||||||||||||||
Non-trading activities |
||||||||||||||||||||||
Economic hedges |
$ | 87 | $ | 367 | $ | 454 | $ | 216 | $ | 449 | $ | 665 | $ | 211 | ||||||||
Netting and collateral |
| | | (4 | ) | | (4 | ) | (4 | ) | ||||||||||||
Total |
$ | 87 | $ | 367 | $ | 454 | $ | 212 | $ | 449 | $ | 661 | $ | 207 | ||||||||
Income Statement Impact of Derivative Instruments
SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and expects to recover these costs from ratepayers. As a result, realized gains and losses are not reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore are also not reflected in 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) |
2011 |
2010 |
2011 |
2010 |
|||||||||
Realized losses |
$ | (35 | ) | $ | (38 | ) | $ | (74 | ) | $ | (62 | ) | |
Unrealized losses |
(227 | ) | (276 | ) | (323 | ) | (857 | ) | |||||
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 historically 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 $164 million and $67 million as of June 30, 2011 and December 31, 2010, respectively, for which SCE has posted no collateral and $4 million of collateral to its
19
counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2011, SCE would be required to post $12 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. All of the contracts that SCE has entered into with counterparties are either entered into under SCE's short-term or long-term procurement plan which has been 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.
Competitive Power Generation
EMG uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EMG's financial results can be affected by fluctuations in interest rates. The derivative financial instruments vary in duration, ranging from a few days to several years, depending upon the instrument. To the extent that EMG does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.
Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on EMG's consolidated balance sheets with offsetting changes recorded on the consolidated statements of operations. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized, to the extent effective, on EMG's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive loss until the related forecasted transaction occurs. The results of derivative activities are recorded in cash flows from operating activities on the consolidated statements of cash flows.
Derivative instruments that are utilized for trading purposes are measured at fair value and included on the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues on the consolidated statements of operations.
Where EMG's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EMG presents its derivative assets and liabilities on a net basis on its consolidated balance sheets.
20
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging and trading activities:
June 30, 2011 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
Hedging Activities | |
|||||||||||
Commodity |
Instrument |
Classification |
Unit of Measure |
Cash Flow Hedges |
Economic Hedges |
Trading Activities |
||||||||||
Electricity | Forwards/Futures | Sales | GWh | 18,901 | 1 | 17,660 | 3 | 39,629 | ||||||||
Electricity | Forwards/Futures | Purchases | GWh | 203 | 1 | 17,750 | 3 | 42,863 | ||||||||
Electricity | Capacity | Sales | MW-Day (in thousands) |
171 | 2 | | 17 | 2 | ||||||||
Electricity | Capacity | Purchases | MW-Day (in thousands) |
17 | 2 | | 247 | 2 | ||||||||
Electricity | Congestion | Sales | GWh | | 124 | 4 | 14,314 | 4 | ||||||||
Electricity | Congestion | Purchases | GWh | | 5,459 | 4 | 287,221 | 4 | ||||||||
Natural gas | Forwards/Futures | Sales | bcf | | 1.5 | 354.1 | ||||||||||
Natural gas | Forwards/Futures | Purchases | bcf | | 1.5 | 351.8 | ||||||||||
Fuel oil | Forwards/Futures | Sales | barrels | | | 45,000 | ||||||||||
Fuel oil | Forwards/Futures | Purchases | barrels | | 240,000 | 70,000 | ||||||||||
Coal | Forwards/Futures | Sales | tons | | | 2,564,250 | ||||||||||
Coal | Forwards/Futures | Purchases | tons | | | 2,564,250 | ||||||||||
(in millions) | |||||||||
---|---|---|---|---|---|---|---|---|---|
Instrument |
Purpose |
Type of Hedge |
Notional Amount |
Expiration Date |
|||||
Amortizing interest rate swap | Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt | Cash flow | $ | 84 | June 2016 | ||||
Amortizing interest rate swap |
Convert floating rate (6-month LIBOR) debt to fixed rate (3.415%) debt |
Cash flow |
110 |
December 2020 |
|||||
Amortizing interest rate swap |
Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt |
Cash flow |
120 |
December 2025 |
|||||
Amortizing interest rate swap |
Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt |
Cash flow |
67 |
March 2026 |
|||||
21
December 31, 2010 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
Hedging Activities | |
|||||||||||
Commodity |
Instrument |
Classification |
Unit of Measure |
Cash Flow Hedges |
Economic Hedges |
Trading Activities |
||||||||||
Electricity | Forwards/Futures | Sales | GWh | 16,799 | 1 | 22,456 | 3 | 34,630 | ||||||||
Electricity | Forwards/Futures | Purchases | GWh | 408 | 1 | 22,931 | 3 | 37,669 | ||||||||
Electricity | Capacity | Sales | MW-Day (in thousands) |
190 | 2 | | 136 | 2 | ||||||||
Electricity | Capacity | Purchases | MW-Day (in thousands) |
8 | 2 | | 419 | 2 | ||||||||
Electricity | Congestion | Sales | GWh | | 136 | 4 | 12,020 | 4 | ||||||||
Electricity | Congestion | Purchases | GWh | | 1,143 | 4 | 187,689 | 4 | ||||||||
Natural gas | Forwards/Futures | Sales | bcf | | | 30.6 | ||||||||||
Natural gas | Forwards/Futures | Purchases | bcf | | | 34.3 | ||||||||||
Fuel oil | Forwards/Futures | Sales | barrels | | 250,000 | 10,000 | ||||||||||
Fuel oil | Forwards/Futures | Purchases | barrels | | 490,000 | 10,000 | ||||||||||
Coal | Forwards/Futures | Sales | tons | | | 2,630,500 | ||||||||||
Coal | Forwards/Futures | Purchases | tons | | | 2,645,500 | ||||||||||
(in millions) | |||||||||
---|---|---|---|---|---|---|---|---|---|
Instrument |
Purpose |
Type of Hedge |
Notional Amount |
Expiration Date |
|||||
Amortizing interest rate swap | Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt | Cash flow | $ | 138 | June 2016 | ||||
Amortizing forward starting interest rate swap |
Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt |
Cash flow |
122 |
December 2025 |
|||||
Amortizing forward starting interest rate swap |
Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt |
Cash flow |
68 |
March 2026 |
|||||
22
Fair Value of Derivative Instruments
The following table summarizes the fair value of derivative instruments reflected on EMG's consolidated balance sheets:
June 30, 2011 | |||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Derivative Assets | Derivative Liabilities | |
||||||||||||||||||||
|
Net Assets (Liabilities) |
||||||||||||||||||||||
(in millions) |
Short-term |
Long-term |
Subtotal |
Short-term |
Long-term |
Subtotal |
|||||||||||||||||
Non-trading activities |
|||||||||||||||||||||||
Cash flow hedges |
$ | 27 | $ | 2 | $ | 29 | $ | 14 | $ | 34 | $ | 48 | $ | (19 | ) | ||||||||
Economic hedges |
60 | 4 | 64 | 51 | 1 | 52 | 12 | ||||||||||||||||
Trading activities |
141 | 88 | 229 | 98 | 20 | 118 | 111 | ||||||||||||||||
|
228 | 94 | 322 | 163 | 55 | 218 | 104 | ||||||||||||||||
Netting and collateral received1 |
(189 | ) | (31 | ) | (220 | ) | (157 | ) | (32 | ) | (189 | ) | (31 | ) | |||||||||
Total |
$ | 39 | $ | 63 | $ | 102 | $ | 6 | $ | 23 | $ | 29 | $ | 73 | |||||||||
December 31, 2010 |
|
|
|
|
|
|
|
||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Non-trading activities |
|||||||||||||||||||||||
Cash flow hedges |
$ | 54 | $ | 2 | $ | 56 | $ | 10 | $ | 25 | $ | 35 | $ | 21 | |||||||||
Economic hedges |
77 | 2 | 79 | 71 | | 71 | 8 | ||||||||||||||||
Trading activities |
184 | 103 | 287 | 148 | 29 | 177 | 110 | ||||||||||||||||
|
315 | 107 | 422 | 229 | 54 | 283 | 139 | ||||||||||||||||
Netting and collateral received1 |
(269 | ) | (37 | ) | (306 | ) | (223 | ) | (35 | ) | (258 | ) | (48 | ) | |||||||||
Total |
$ | 46 | $ | 70 | $ | 116 | $ | 6 | $ | 19 | $ | 25 | $ | 91 | |||||||||
Income Statement Impact of Derivative Instruments
The following table provides the cash flow hedge activity as part of accumulated other comprehensive loss:
|
Cash Flow Hedge Activity1 Six Months Ended June 30, |
|
||||||
---|---|---|---|---|---|---|---|---|
|
Income Statement Location |
|||||||
(in millions) |
2011 |
2010 |
||||||
Beginning of period derivative gains |
$ | 27 | $ | 175 | ||||
Effective portion of changes in fair value |
(13 | ) | 30 | |||||
Reclassification to net income |
(29 | ) | (122 | ) | Competitive power generation revenue | |||
End of period derivative gains (losses) |
$ | (15 | ) | $ | 83 | |||
For additional information, see Note 11Accumulated Other Comprehensive Loss.
The portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EMG recorded net gains (losses) of none and $(7) million during the second quarters of 2011 and 2010, respectively, and $2 million and $1 million during the six months ended June 30, 2011 and 2010, respectively, in operating revenues on the consolidated statements of operations representing the amount of cash flow hedge ineffectiveness.
23
The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading purposes on the consolidated statements of operations is presented below:
|
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Income Statement Location |
2011 |
2010 |
2011 |
2010 |
||||||||||
Economic hedges |
Competitive power generation revenue | $ | 20 | $ | (3 | ) | $ | 26 | $ | (7 | ) | ||||
|
Fuel | (2 | ) | (2 | ) | 4 | (1 | ) | |||||||
Trading activities |
Competitive power generation revenue |
41 |
33 |
57 |
80 |
||||||||||
Contingent Features
Certain derivative instruments contain margin and collateral deposit requirements. Since EMG's subsidiaries' credit ratings are below investment grade, EMG's subsidiaries have provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties. The aggregate fair value of all derivative instruments with credit-risk-related contingent features was in an asset position at June 30, 2011 and, accordingly, the contingent features described below do not currently have liquidity exposure. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EMG or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. Edison Mission Marketing & Trading, Inc. ("EMMT") has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. Future increases in power prices could expose EMG's subsidiaries to termination payments or additional collateral postings.
Margin and Collateral Deposits
Margin and collateral deposits include cash deposited with counterparties and brokers, and cash received from 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. Edison International nets counterparty receivables and payables where balances exist under master netting agreements. Edison International 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 and received from counterparties:
(in millions) |
June 30, 2011 |
December 31, 2010 |
||||||
---|---|---|---|---|---|---|---|---|
Collateral provided to counterparties: |
||||||||
Offset against derivative liabilities |
$ | 4 | $ | 8 | ||||
Reflected in margin and collateral deposits |
64 | 65 | ||||||
Collateral received from counterparties: |
||||||||
Offset against derivative assets |
33 | 52 | ||||||
24
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations.
|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
2011 |
2010 |
|||||||||||
Income from continuing operations before income taxes |
$ | 254 | $ | 220 | $ | 535 | $ | 612 | |||||||
Provision for income tax at federal statutory rate of 35% |
89 | 77 | 187 | 214 | |||||||||||
Increase (decrease) in income tax from: |
|||||||||||||||
Items presented with related state income tax, net: |
|||||||||||||||
Global Settlement related1 |
| (138 | ) | | (138 | ) | |||||||||
Change in tax accounting method for asset removal costs2 |
| (40 | ) | | (40 | ) | |||||||||
State tax net of federal benefit |
4 | 16 | 13 | 23 | |||||||||||
Health care legislation3 |
| | | 39 | |||||||||||
Production and housing credits |
(19 | ) | (19 | ) | (36 | ) | (34 | ) | |||||||
Property-related and other |
(12 | ) | (32 | ) | (37 | ) | (50 | ) | |||||||
Total income tax expense from continuing operations |
$ | 62 | $ | (136 | ) | $ | 127 | $ | 14 | ||||||
Effective tax rate |
24% | (62% | ) | 24% | 2% | ||||||||||
The decreased benefit provided by property-related and other items was primarily due to lower deductions for internally developed software in 2011 compared to the respective periods in 2010.
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.
Accounting for Uncertainty in Income Taxes
Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination. The guidance requires the disclosure of all unrecognized tax benefits, which includes both the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.
25
The following table provides a reconciliation of unrecognized tax benefits:
(in millions) |
2011 |
2010 |
||||||
---|---|---|---|---|---|---|---|---|
Balance at January 1, |
$ | 565 | $ | 664 | ||||
Tax positions taken during the current year: |
||||||||
Increases |
26 | 35 | ||||||
Tax positions taken during a prior year: |
||||||||
Increases |
14 | 127 | ||||||
Decreases |
(10 | ) | (40 | ) | ||||
Decreases for settlements during the period |
| (82 | ) | |||||
Balance at June 30, |
$ | 595 | $ | 704 | ||||
As of June 30, 2011 and December 31, 2010, $468 million and $455 million, respectively, of the unrecognized tax benefits, if recognized, would impact the effective tax rate.
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, which included proposed adjustments for the following two items:
Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011.
Accrued Interest and Penalties
The total amount of accrued interest and penalties related to Edison International's income tax liabilities was $222 million and $213 million as of June 30, 2011 and December 31, 2010, respectively.
The net after-tax interest and penalties recognized in income tax expense was $2 million and $5 million for the three- and six-month periods ended June 30, 2011, respectively, compared to a benefit of $101 million and $88 million for the same periods in 2010.
Note 8. Compensation and Benefit Plans
Pension Plans and Postretirement Benefits Other Than Pensions
During the six months ended June 30, 2011, Edison International made contributions of $61 million and during the remainder of 2011, expects to make $69 million of additional contributions. Annual contributions made to most of SCE's pension plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.
26
Expense components are:
|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
2011 |
2010 |
|||||||||
Service cost |
$ | 43 | $ | 34 | $ | 86 | $ | 68 | |||||
Interest cost |
52 | 54 | 104 | 108 | |||||||||
Expected return on plan assets |
(60 | ) | (52 | ) | (120 | ) | (104 | ) | |||||
Amortization of prior service cost |
2 | 2 | 4 | 4 | |||||||||
Amortization of net loss |
6 | 7 | 12 | 14 | |||||||||
Expense under accounting standards |
43 | 45 | 86 | 90 | |||||||||
Regulatory adjustment deferred |
(6 | ) | (14 | ) | (12 | ) | (28 | ) | |||||
Total expense recognized |
$ | 37 | $ | 31 | $ | 74 | $ | 62 | |||||
Postretirement Benefits Other Than Pensions
During the six months ended June 30, 2011, Edison International made contributions of $12 million and during the remainder of 2011, expects to make $44 million of additional contributions. Annual contributions made to SCE's plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.
Expense components are:
|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
2011 |
2010 |
|||||||||
Service cost |
$ | 11 | $ | 8 | $ | 22 | $ | 16 | |||||
Interest cost |
33 | 31 | 66 | 62 | |||||||||
Expected return on plan assets |
(28 | ) | (25 | ) | (56 | ) | (50 | ) | |||||
Amortization of prior service cost (credit) |
(9 | ) | (9 | ) | (18 | ) | (18 | ) | |||||
Amortization of net loss |
9 | 8 | 18 | 16 | |||||||||
Total expense |
$ | 16 | $ | 13 | $ | 32 | $ | 26 | |||||
During the six months ended June 30, 2011, Edison International granted its 2011 stock-based compensation awards, which included stock options, performance shares and restricted stock units.
The following is a summary of the status of Edison International stock options:
|
|
Weighted-Average | |
||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Stock options |
Exercise Price |
Remaining Contractual Term (Years) |
Aggregate Intrinsic Value (in millions) |
|||||||||
Outstanding at December 31, 2010 |
19,142,209 | $ | 33.28 | ||||||||||
Granted |
3,314,149 | 37.95 | |||||||||||
Expired |
(87,641 | ) | 47.93 | ||||||||||
Forfeited |
(244,066 | ) | 32.52 | ||||||||||
Exercised |
(1,002,771 | ) | 24.74 | ||||||||||
Outstanding at June 30, 2011 |
21,121,880 | 34.37 | 6.26 | ||||||||||
Vested and expected to vest at June 30, 2011 |
20,639,870 | 34.38 | 6.21 | $ | 136 | ||||||||
Exercisable at June 30, 2011 |
12,613,025 | 34.70 | 4.74 | 93 | |||||||||
27
At June 30, 2011, there was $28 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately three years.
The following is a summary of the status of Edison International nonvested performance shares:
|
Equity Awards | Liability Awards | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Shares |
Weighted-Average Grant Date Fair Value |
Shares |
Weighted-Average Fair Value |
|||||||||
Nonvested at December 31, 2010 |
415,028 | $ | 30.99 | 415,028 | $ | 34.74 | |||||||
Granted |
148,697 | 27.96 | 148,697 | ||||||||||
Forfeited |
(113,762 | ) | 43.42 | (113,762 | ) | ||||||||
Nonvested at June 30, 2011 |
449,963 | 28.04 | 449,963 | 29.43 | |||||||||
The current portion of nonvested performance shares classified as liability awards is reflected in "Other current liabilities" and the long-term portion is reflected in "Pensions and benefits" on the consolidated balance sheets.
At June 30, 2011, there was $6 million of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately two years.
The following is a summary of the status of Edison International nonvested restricted stock units:
|
Restricted Stock Units |
Weighted-Average Grant Date Fair Value |
|||||
---|---|---|---|---|---|---|---|
Nonvested at December 31, 2010 |
644,796 | $ | 32.18 | ||||
Granted |
247,408 | 37.95 | |||||
Forfeited |
(16,467 | ) | 32.13 | ||||
Paid Out |
(104,420 | ) | 52.35 | ||||
Nonvested at June 30, 2011 |
771,317 | $ | 31.98 | ||||
At June 30, 2011, there was $12 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $4 million in 2011, $5 million in 2012 and $3 million in 2013.
28
Supplemental Data on Stock Based Compensation
|
Three months ended June 30, |
Six months ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
2011 |
2010 |
||||||||||
Stock based compensation expense1 |
$ | 11 | $ | 9 | $ | 17 | $ | 17 | ||||||
Income tax benefits related to stock compensation expense |
5 | 4 | 7 | 7 | ||||||||||
Excess tax benefits2 |
2 | 1 | 4 | 2 | ||||||||||
Stock options |
||||||||||||||
Cash used to purchase shares to settle options |
20 | 6 | 39 | 13 | ||||||||||
Cash from participants to exercise stock options |
12 | 4 | 25 | 9 | ||||||||||
Value of options exercised |
8 | 2 | 14 | 4 | ||||||||||
Restricted stock units |
||||||||||||||
Value of shares settled |
| | 5 | | ||||||||||
Tax benefits realized from settlement of awards |
| | 2 | | ||||||||||
No performance shares were settled for both the six month periods ended June 30, 2011 and 2010.
Note 9. Commitments and Contingencies
Third-Party Power Purchase Agreements
At June 30, 2011, additional renewable energy power purchase contracts became effective and were classified as operating leases. SCE's additional commitments under these contracts are estimated to be: $6 million in 2011, $116 million each year in 2012 2015 and $1.9 billion for the period remaining thereafter.
At June 30, 2011, Midwest Generation and EME Homer City Generation L.P. ("Homer City") had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses. These commitments are estimated to aggregate $634 million, summarized as follows: $277 million for the remainder of 2011, $304 million in 2012 and $53 million in 2013. In July 2011, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments are estimated to be $6 million for the remainder of 2011, $28 million for 2012, $145 million for 2013 and $150 million for 2014.
At June 30, 2011, EMG had commitments to purchase wind turbines of $45 million due in 2011 and $8 million due in 2012. Based on a June 2011 contract amendment, EMG's failure to schedule turbine delivery by September 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $29 million charge against earnings. EMG has identified a project in which to place these turbines. However, there is no assurance that development will be completed and the turbines will be used for this project.
On October 8, 2010, an agreement was reached to settle disputes included in the complaint filed by EMG against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. As a result of this agreement, EMG may elect to deploy up to 60 additional wind turbines (aggregating 144 MW) that were part of the original contract, or may be obligated to make a payment of up to $30 million following the end of the three-year period if it has not elected to deploy the additional turbines and if certain other criteria apply.
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At June 30, 2011, EMG's subsidiaries had firm commitments to spend approximately $242 million during the remainder of 2011, $205 million in 2012 and $19 million in 2013 on capital and construction expenditures. These expenditures primarily relate to the Walnut Creek project, selective non-catalytic reduction (SNCR) equipment at the Midwest Generation plants, and the construction of wind projects. EMG intends to fund these expenditures through project level financing, U.S. Treasury grants, Midwest Generation and EME lines of credit, if available, cash on hand and cash generated from operations.
Edison International's subsidiaries have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business. The contracts discussed below included performance guarantees.
Environmental Indemnities Related to the Midwest Generation Plants
In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison Company ("Commonwealth Edison") with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification obligations are reduced by any insurance proceeds and tax benefits related to such indemnified claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the lessors for specified environmental liabilities. These indemnities are not limited in term or amount. Due to the nature of the obligations under these indemnities, a maximum potential liability cannot be determined. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the litigation discussed below under "ContingenciesMidwest Generation New Source Review and Other Litigation." Except as discussed below, EME has not recorded a liability related to these environmental indemnities.
Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of Midwest Generation's reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2012. There were approximately 222 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at June 30, 2011. Midwest Generation had recorded a liability of $55 million at June 30, 2011 related to this contractual indemnity.
The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.
Environmental Indemnity Related to the Homer City Plant
In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. EME guaranteed this obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity provisions, they are not subject to a maximum potential liability and do not have expiration dates. EME has not recorded a liability related to this indemnity. For discussion of the New Source Review lawsuit filed against Homer City, see "ContingenciesHomer City New Source Review and Other Litigation."
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Indemnities Provided under Asset Sale and Sale-Leaseback Agreements
The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. At June 30, 2011, EME had recorded a liability of $45 million related to these matters.
In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the assets prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Not all indemnities under the asset sale agreements have specific expiration dates. Due to the nature of these potential obligations, a maximum potential liability cannot be determined and has not been recorded as a liability related to these indemnities.
In connection with the sale-leaseback transactions related to the Homer City plant in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability for these matters.
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
The Mountainview power plant utilizes water from on-site groundwater wells and City of Redlands ("City") recycled water for cooling purposes. Unrelated to the operation of the plant, the groundwater contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant's wastewater treatment "filter cake." Use of this impacted groundwater for cooling purposes was mandated by Mountainview's California Energy Commission permit. SCE has indemnified the City 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 Edison International Indemnities
Edison International 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. Edison International's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances Edison International may have recourse against third parties. Edison International has not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.
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In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.
Midwest Generation New Source Review and Other Litigation
In August 2009, the United States Environmental Protection Agency ("US EPA") and the State of Illinois filed a complaint in the Northern District of Illinois alleging that Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration ("PSD") requirements and of the New Source Performance Standards of the Clean Air Act ("CAA"), including alleged requirements to obtain a construction permit and to install controls sufficient to meet best available control technology ("BACT") emission rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond the requirements of the Combined Pollutant Standard ("CPS"). Several Chicago-based environmental action groups have intervened in the case.
Nine of ten PSD claims have been dismissed, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court has also dismissed all claims asserted against Commonwealth Edison and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations should be equitably tolled. The court did not address other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. Trial of the liability portion of the case is scheduled to commence June 3, 2013.
In May 2011, two complaints were filed against Midwest Generation in the Northern District of Illinois by residents living near the Crawford and Fisk facilities on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive relief, as well as compensatory and punitive damages.
Adverse decisions in these cases could involve penalties and remedial actions that could have a material impact on the financial condition and results of operations of Midwest Generation and EME. EME cannot predict the outcome of these matters or estimate the impact on the Midwest Generation plants, or its and Midwest Generation's results of operations, financial position or cash flows.
Homer City New Source Review and Other Litigation
In January 2011, the US EPA filed a complaint in the Western District of Pennsylvania against Homer City, the sale-leaseback owner participants of the Homer City plant, and two prior owners of the Homer City plant. The complaint alleges violations of the PSD and Title V provisions of the CAA, as a result of projects in the 1990s performed by prior owners without PSD permits and the subsequent failure to incorporate emissions limitations that meet BACT into the station's Title V operating permit. In addition to seeking penalties ranging from $32,500 to $37,500 per violation, per day, the complaint calls for an injunction ordering Homer City to install controls sufficient to meet BACT emission rates at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the
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environment caused by the alleged CAA violations. The Pennsylvania Department of Environmental Protection, the State of New York and the State of New Jersey have intervened in the lawsuit.
Also in January 2011, two residents filed a complaint in the Western District of Pennsylvania, on behalf of themselves and all others similarly situated, against Homer City, the sale-leaseback owner participants of the Homer City plant, two prior owners of the Homer City plant, EME, and Edison International, claiming that emissions from the Homer City plant had adversely affected their health and property values. The plaintiffs seek to have their suit certified as a class action and request injunctive relief, the funding of a health assessment study and medical monitoring, as well as compensatory and punitive damages.
In April 2011, Homer City filed motions to dismiss both complaints. Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on the financial condition and results of operations of Homer City and EME. EME cannot predict the outcome of these matters or estimate the impact on the Homer City plant, or its and Homer City's results of operations, financial position or cash flows.
On August 1, 2011, SCE and the other defendants entered into a comprehensive settlement with the Navajo Nation of the litigation filed in June 1999 against SCE and others concerning royalty payments to the Navajo for the coal supplied to the Mohave Generating Station. As amended in April 2010, the Navajo Nation's complaint asserted claims for, among other things, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The settlement will result in a payment to the Navajo Nation and other related parties. As a result of the settlement, the Navajo Nation lawsuit will be dismissed. The settlement agreement reached with the Navajo Nation will not impact SCE's results of operations.
Edison International 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. Edison International 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, operations and maintenance, monitoring and site closure. Unless there is a single probable amount, Edison International 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.
As of June 30, 2011, Edison International's recorded estimated minimum liability to remediate its 26 identified material sites (sites in which the upper end of the range of costs is at least $1 million) at SCE (24 sites) and EMG (2 sites primarily related to Midwest Generation) was $60 million, of which $54 million was related to SCE, including $18 million related to San Onofre. In addition to its identified material sites, SCE also has 33 immaterial sites for which the total minimum recorded liability was $3 million. The ultimate costs to clean up Edison International'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. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs at these identified material sites and immaterial sites could exceed its recorded liability by up to $192 million and $7 million, respectively, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes.
The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $32 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). In addition, SCE expects to recover 100% of environmental remediation costs incurred at the majority of the remaining sites through customer rates, representing $21 million of its recorded liability. SCE has recorded a regulatory asset of $53 million at June 30, 2011 for its estimated minimum environmental cleanup costs expected to be recovered through customer rates.
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Edison International'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 Edison International 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.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $5 million to $17 million. Costs incurred for the six months ended June 30, 2011 and 2010, were $7 million and $3 million, respectively.
Based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International 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.
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.
Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. 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 $48 million per year. Insurance premiums are charged to operating expense.
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 its 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. The decision has been appealed by the DOE. Additional legal action would be necessary to recover damages incurred after that date. Any damages recovered would be returned to SCE ratepayers or used to offset past or future fuel decommissioning or storage costs for the benefit of ratepayers.
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Note 10. Regulatory and Environmental Developments
Environmental Developments
Cross-State Air Pollution Rule
On July 6, 2011, the US EPA adopted its final Cross-State Air Pollution Rule ("CSAPR") which will replace the Clean Air Interstate Rule ("CAIR") beginning on January 1, 2012. CSAPR is the final form of a previously proposed replacement for the CAIR, called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual sulfur dioxide ("SO2") emissions and annual ozone season nitrogen oxide ("NOx") emissions in two phases: a first phase effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO2 emissions.
CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO2 or NOx emissions from operations will need to be matched by a sufficient amount of SO2 or NOx allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO2 and NOx allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual compliance period, units must surrender allowances for each ton of SO2 and NOx emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for enhanced penalties against a unit that surrenders allowances in excess of certain predefined limits for itself and for the state in which it is located.
The installation of SO2 controls will require capital commitments for the Midwest Generation plants well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. EMG believes that Midwest Generation's current environmental remediation plan, including allocated allowances and capital expenditures, required to meet the CPS will also comply with the requirements of CSAPR. However, the SO2 allowances allocated to Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) are significantly lower than the amount that would be required based on Homer City's historical emissions (2010 SO2 emissions were 112,951 tons). Therefore, pending installation of additional equipment for Units 1 and 2 (Homer City's Unit 3 is equipped with a wet scrubber flue gas desulfurization system to meet environmental standards), Homer City expects that it will be required to procure additional allowances. It is unclear at this time whether SO2 allowances in sufficient quantity and at prices that Homer City can pass through in power prices will be available in 2012 and 2013. Also, Homer City's SO2 shortfall is expected to exceed limits on the number of allowances it will be permitted to surrender, and, therefore, may subject Homer City to penalties in certain cases. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel switching, for complying with Phase I of CSAPR. Failure by Homer City to develop and implement a Phase I compliance plan based on allowances could result in its modifying operations at one or more units or significantly curtailing power output. The cost of allowances, together with possible operational impacts or reductions of output, which may be required to comply with Phase I of CSAPR, could have a material effect on Homer City.
Homer City has begun work on designing SO2 and particulate emissions control equipment for Units 1 and 2. While the Phase II SO2 emission allowances under CSAPR (11,068 tons) are less than were contemplated under the proposed Clean Air Transport Rule, the additional reductions are not expected to materially change the design for the SO2 controls at Units 1 and 2. The installation of those SO2 controls will require capital commitments for the Homer City plant well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. Given the relatively short period of time before Phase II of CSAPR takes effect in 2014, there is no assurance that Homer City will be able to complete all the work that will be required before the deadline. Homer City is continuing to review technologies available to reduce SO2 and mercury emissions; however, it has not determined the most effective and efficient technology to meet all requirements that may be imposed on it. Consequently, the timing, selection of technology and ultimate capital costs remain uncertain. Based on preliminary estimates, Homer City currently believes the cost of such equipment may be between $600 million and $700 million.
Homer City does not currently have sufficient capital and does not expect to generate sufficient capital from operations to fund such retrofits and will have to seek financing, which will be subject to decisions by Homer City's lessors, holders of the pass-through certificates and new providers of capital funding. There is
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no assurance that sufficient financing will be obtained or will not result in significant dilution of Homer City's interest in the Homer City plant.
Proposed Hazardous Air Pollutant Regulations
In March 2011, the US EPA issued proposed National Emission Standards for Hazardous Air Pollutants, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. This regulation is expected to be finalized by November 2011. Based on its continuing review, EMG does not expect that these standards, if adopted as proposed, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. EMG also does not expect that these standards, if adopted as proposed, would require Homer City to make additional capital requirements beyond those that would be required to comply with CSAPR.
Water Quality
Once-Through Cooling Issues
In March 2011, the US EPA issued proposed standards under the federal Clean Water Act which would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). The regulations are expected to be finalized by July 2012. Edison International is evaluating the proposed standards and believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable for both the Midwest Generation plants and the Homer City plant without incurring material additional capital expenditures or operating costs. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and Edison International is unable at this time to assess potential costs of compliance, which could be significant for the Midwest Generation plants and San Onofre, but are not expected to be material for the Homer City plant, which already has cooling towers.
In addition to the proposed draft US EPA standards, the existing California once-through cooling policy may result in significant capital expenditures at San Onofre and may affect its operations. If other coastal power plants in California that rely on once-through cooling are forced to shut down or limit operations, the California policy may also significantly impact SCE's ability to procure generating capacity from those plants, which could have an adverse effect on system reliability and the cost of electricity.
Greenhouse Gas Regulation
California Air Resources Board's ("CARB") regulations implementing a California cap-and-trade program continue to be the subject of litigation. In June 2011, the CARB announced that initial cap-and-trade program compliance for the electricity sector would be delayed until January 2013.
In April 2011, California enacted a law requiring that California utilities to procure 33% of their electricity requirements from renewable resources, as defined in the statute. The law requires implementation by the CPUC. The impact of the new 33% law will depend on how the CPUC implements the law, which remains uncertain.
Greenhouse Gas Litigation Developments
In June 2011, the U.S. Supreme Court dismissed public nuisance claims against five power companies, ruling that the CAA and the US EPA actions it authorizes displace federal common law nuisance claims that might arise from the emission of greenhouse gases. The court also affirmed the Second Circuit's determination that at least some of the plaintiffs had standing to bring the case. The court did not address whether the CAA also preempts state law claims arising from the same circumstances.
Parties to the Kivalina case, the appeal of which was deferred before the Ninth Circuit Court of Appeals pending the Supreme Court's ruling described above, have requested that the appeal recommence and have asked for permission to file additional briefs on the impact of the Supreme Court's ruling. The Kivalina case was brought by the Alaskan Native Village of Kivalina seeking damages of up to $400 million for the
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cost of relocating the village because the plaintiffs claim that the Arctic ice that has protected the village is melting as a result of climate change. The federal district court dismissed the case against Edison International and the other defendants in October 2009. Due to the nature of these potential obligations, Edison International is unable to estimate the potential liability, if any.
On May 27, 2011, private citizens filed a purported class action complaint in the United States District Court for the Southern District of Mississippi, naming among a large number of defendants, Edison International and its subsidiaries, including SCE and EME. Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of 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. Accumulated Other Comprehensive Loss
Edison International's accumulated other comprehensive loss consists of:
(in millions) |
Unrealized Gain (Loss) on Cash Flow Hedges |
Pension and PBOP Net Gain (Loss) |
Pension and PBOP Prior Service Cost |
Accumulated Other Comprehensive Loss |
|||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2010 |
$ | 16 | $ | (87 | ) | $ | (5 | ) | $ | (76 | ) | ||
Current period change |
(25 | ) | 4 | | (21 | ) | |||||||
Balance at June 30, 2011 |
$ | (9 | ) | $ | (83 | ) | $ | (5 | ) | $ | (97 | ) | |
Included in accumulated other comprehensive loss at June 30, 2011 was $4 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $13 million, net of tax, of unrealized losses related to interest rate hedges. The maximum period over which a commodity cash flow hedge is designated is May 31, 2014.
Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $8 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenues recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.
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Note 12. Supplemental Cash Flows Information
Edison International's supplemental cash flows information is:
|
Six months ended June 30, |
||||||||
---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
|||||||
Cash payments (receipts) for interest and taxes: |
|||||||||
Interest net of amounts capitalized |
$ | 321 | $ | 305 | |||||
Tax payments (refunds) net |
(44 | ) | 179 | ||||||
Noncash investing and financing activities: |
|||||||||
Accrued capital expenditures |
$ | 388 | $ | 333 | |||||
Purchase of equipment with note payable |
$ | 56 | $ | | |||||
Details of debt exchange: |
|||||||||
Pollution-control bonds redeemed |
$ | (56 | ) | $ | (203 | ) | |||
Pollution-control bonds issued |
56 | 203 | |||||||
Consolidation of variable interest entities: |
|||||||||
Assets other than cash |
$ | | $ | (94 | ) | ||||
Liabilities and non-controlling interests |
| 99 | |||||||
Deconsolidation of variable interest entities: |
|||||||||
Assets other than cash |
$ | | $ | 380 | |||||
Liabilities and noncontrolling interests |
| (476 | ) | ||||||
Dividends declared but not paid: |
|||||||||
Common stock |
$ | 104 | $ | 103 | |||||
Preferred and preference stock |
15 | 13 | |||||||
Note 13. Preferred and Preference Stock of Utility
In March 2011, SCE issued 1,250,000 shares of 6.5% Series D preference stock (cumulative, $100 liquidation value). The Series D preference stock may not be redeemed prior to March 1, 2016. After March 1, 2016, SCE may, at its option, redeem the shares, in whole or in part for a price of $100 per share plus accrued and unpaid dividends, if any. These shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used for general corporate purposes.
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Note 14. Regulatory Assets and Liabilities
Regulatory assets included on the consolidated balance sheets are:
(in millions) |
June 30, 2011 |
December 31, 2010 |
||||||
---|---|---|---|---|---|---|---|---|
Current: |
||||||||
Regulatory balancing accounts |
$ | 268 | $ | 213 | ||||
Energy derivatives |
194 | 162 | ||||||
Other |
7 | 3 | ||||||
|
469 | 378 | ||||||
Long-term: |
||||||||
Deferred income taxes net |
1,912 | 1,855 | ||||||
Pensions and other postretirement benefits |
1,089 | 1,097 | ||||||
Unamortized generation investment net |
328 | 355 | ||||||
Unamortized loss on reacquired debt |
258 | 268 | ||||||
Energy derivatives |
465 | 177 | ||||||
Nuclear-related ARO investment net |
163 | 154 | ||||||
Unamortized distribution investment net |
125 | 105 | ||||||
Regulatory balancing accounts |
53 | 56 | ||||||
Other |
297 | 280 | ||||||
|
4,690 | 4,347 | ||||||
Total Regulatory Assets |
$ | 5,159 | $ | 4,725 | ||||
Regulatory liabilities included on the consolidated balance sheets are:
(in millions) |
June 30, 2011 |
December 31, 2010 |
|||||
---|---|---|---|---|---|---|---|
Current: |
|||||||
Regulatory balancing accounts |
$ | 818 | $ | 733 | |||
Other |
2 | 5 | |||||
|
820 | 738 | |||||
Long-term: |
|||||||
Costs of removal |
2,663 | 2,623 | |||||
ARO |
1,250 | 1,099 | |||||
Regulatory balancing accounts |
846 | 802 | |||||
|
4,759 | 4,524 | |||||
Total Regulatory Liabilities |
$ | 5,579 | $ | 5,262 | |||
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 included in 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, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.
39
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, 2011 |
December 31, 2010 |
June 30, 2011 |
December 31, 2010 |
||||||||||
Stocks |
| $ | 862 | $ | 895 | $ | 2,062 | $ | 2,029 | ||||||
Municipal bonds |
2050 | 699 | 706 | 812 | 790 | ||||||||||
U.S. government and agency securities |
2041 | 396 | 270 | 427 | 288 | ||||||||||
Corporate bonds |
2054 | 255 | 288 | 310 | 346 | ||||||||||
Short-term investments and receivables/payables |
One-year | 44 | 26 | 46 | 27 | ||||||||||
Total |
$ | 2,256 | $ | 2,185 | $ | 3,657 | $ | 3,480 | |||||||
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 $524 million and $315 million for the three months ended June 30, 2011 and 2010, respectively, and $1.1 billion and $600 million for the six months ended June 30, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.4 billion and $1.3 billion at June 30, 2011 and December 31, 2010, 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) |
2011 |
2010 |
2011 |
2010 |
|||||||||
Balance at beginning of period |
$ | 3,619 | $ | 3,248 | $ | 3,480 | $ | 3,140 | |||||
Realized gains net |
12 | 13 | 35 | 34 | |||||||||
Unrealized gains (losses) net |
4 | (205 | ) | 106 | (143 | ) | |||||||
Other-than-temporary impairments |
(4 | ) | (7 | ) | (13 | ) | (11 | ) | |||||
Interest, dividends, contributions and other |
26 | 34 | 49 | 63 | |||||||||
Balance at end of period |
$ | 3,657 | $ | 3,083 | $ | 3,657 | $ | 3,083 | |||||
Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on operating revenue or earnings.
Note 16. Other Income and Expenses
Other income and expenses are as follows:
|
Three months ended June 30, |
Six months ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
2011 |
2010 |
||||||||||
Other income: |
||||||||||||||
Equity AFUDC |
$ | 27 | $ | 25 | $ | 56 | $ | 54 | ||||||
Increase in cash surrender value of life insurance policies |
7 | 6 | 13 | 12 | ||||||||||
Other |
5 | 4 | 8 | 4 | ||||||||||
Total utility other income |
39 | 35 | 77 | 70 | ||||||||||
Competitive power generation and other income |
3 | 1 | 6 | | ||||||||||
Total other income |
$ | 42 | $ | 36 | $ | 83 | $ | 70 | ||||||
Other expenses: |
||||||||||||||
Civic, political and related activities and donations |
$ | 9 | $ | 9 | $ | 15 | $ | 15 | ||||||
Other |
4 | 6 | 10 | 11 | ||||||||||
Total utility other expenses |
13 | 15 | 25 | 26 | ||||||||||
Competitive power generation and other expenses |
| 1 | | 2 | ||||||||||
Total other expenses |
$ | 13 | $ | 16 | $ | 25 | $ | 28 | ||||||
40
Edison International has two business segments for financial reporting purposes: an electric utility operation segment (SCE) and a competitive power generation segment (EMG). The significant accounting policies of the segments are the same as those described in Note 1.
Reportable Segments Information
The following is information (including the elimination of intercompany transactions) related to Edison International's reportable segments:
|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
2011 |
2010 |
|||||||||
Operating Revenue: |
|||||||||||||
Electric utility |
$ | 2,446 | $ | 2,247 | $ | 4,678 | $ | 4,406 | |||||
Competitive power generation |
538 | 495 | 1,090 | 1,147 | |||||||||
Parent and other2 |
(1 | ) | (1 | ) | (2 | ) | (1 | ) | |||||
Consolidated Edison International |
$ | 2,983 | $ | 2,741 | $ | 5,766 | $ | 5,552 | |||||
Net Income (Loss) attributable to Edison International: |
|||||||||||||
Electric utility |
$ | 211 | $ | 301 | $ | 433 | $ | 465 | |||||
Competitive power generation1 |
(31 | ) | 27 | (51 | ) | 104 | |||||||
Parent and other2 |
(4 | ) | 16 | (6 | ) | 11 | |||||||
Consolidated Edison International |
$ | 176 | $ | 344 | $ | 376 | $ | 580 | |||||
Segment balance sheet information was:
(in millions) |
June 30, 2011 |
December 31, 2010 |
||||||
---|---|---|---|---|---|---|---|---|
Total Assets: |
||||||||
Electric utility |
$ | 37,365 | $ | 35,906 | ||||
Competitive power generation |
9,804 | 9,597 | ||||||
Parent and other2 |
(94 | ) | 27 | |||||
Consolidated Edison International |
$ | 47,075 | $ | 45,530 | ||||
41
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Edison International's current expectations and projections about future events based on Edison International'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 Edison International 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 Edison International, include, but are not limited to:
42
Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in Edison International's 2010 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 2010 Form 10-K, and carefully consider the risks, uncertainties and other factors that affect Edison International's business. Forward-looking statements speak only as of the date they are made and Edison International is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International with the U.S. Securities and Exchange Commission.
This MD&A for the three- and six-month periods ended June 30, 2011 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2010, and as compared to the three- and six-month periods ended June 30, 2010. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2010 (the "year-ended 2010 MD&A"), which was included in the 2010 Form 10-K.
43
EDISON INTERNATIONAL MANAGEMENT OVERVIEW
Highlights of Operating Results
|
Three months ended June 30, |
|
Six months ended June 30, |
|
|||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|||||||||||||||||||||
(in millions) |
2011 |
2010 |
Change |
2011 |
2010 |
Change |
|||||||||||||||
Net Income (Loss) attributable to Edison International |
|||||||||||||||||||||
SCE |
$ | 211 | $ | 301 | $ | (90 | ) | $ | 433 | $ | 465 | $ | (32 | ) | |||||||
EMG |
(31 | ) | 27 | (58 | ) | (51 | ) | 104 | (155 | ) | |||||||||||
Edison International Parent and Other |
(4 | ) | 16 | (20 | ) | (6 | ) | 11 | (17 | ) | |||||||||||
Edison International Consolidated |
176 | 344 | (168 | ) | 376 | 580 | (204 | ) | |||||||||||||
Non-Core Items |
|||||||||||||||||||||
Global Settlement: |
|||||||||||||||||||||
SCE |
| 53 | (53 | ) | | 53 | (53 | ) | |||||||||||||
EMG |
| 58 | (58 | ) | | 58 | (58 | ) | |||||||||||||
Edison International Parent and Other |
| 27 | (27 | ) | | 27 | (27 | ) | |||||||||||||
SCE tax impact of health care legislation |
| | | | (39 | ) | 39 | ||||||||||||||
EMG discontinued operations |
(1 | ) | 1 | (2 | ) | (3 | ) | 8 | (11 | ) | |||||||||||
Total non-core items |
(1 | ) | 139 | (140 | ) | (3 | ) | 107 | (110 | ) | |||||||||||
Core Earnings (Losses) |
|||||||||||||||||||||
SCE |
211 | 248 | (37 | ) | 433 | 451 | (18 | ) | |||||||||||||
EMG |
(30 | ) | (32 | ) | 2 | (48 | ) | 38 | (86 | ) | |||||||||||