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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 | |
| NO x | 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) | |
| SO 2 | 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
PART I. FINANCIAL INFORMATION
|
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
|
||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
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
|
|||||||
|---|---|---|---|---|---|---|---|
|
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
|
|||||||
|---|---|---|---|---|---|---|---|---|
|
|
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
|
|||||||
|---|---|---|---|---|---|---|---|
|
Consolidated Statements of Cash Flows
|
|
|
|||||
|
|
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)
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
Revenue—Multiple-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.
8
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 EquityThe 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 | |||||||
9
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 | |||||||
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.
10
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
11
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 MeasurementsRecurring 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).
12
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 Collateral 1 |
Total
|
||||||||||||
|
Assets at Fair Value |
|||||||||||||||||
|
Money market funds 2 |
$ | 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: |
|||||||||||||||||
|
Stocks 3 |
2,062 | — | — | — | 2,062 | ||||||||||||
|
Municipal bonds |
— | 812 | — | — | 812 | ||||||||||||
|
U.S. government and agency securities |
309 | 118 | — | — | 427 | ||||||||||||
|
Corporate bonds 4 |
— | 310 | — | — | 310 | ||||||||||||
|
Short-term investments, primarily cash equivalents 5 |
4 | 31 | — | — | 35 | ||||||||||||
|
Subtotal of nuclear decommissioning trusts |
2,375 | 1,271 | — | — | 3,646 | ||||||||||||
|
Total assets 6 |
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 | |||||
13
|
|
As of December 31, 2010 | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
Level 1
|
Level 2
|
Level 3
|
Netting
and Collateral 1 |
Total
|
||||||||||||
|
Assets at Fair Value |
|||||||||||||||||
|
Money market funds 2 |
$ | 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: |
|||||||||||||||||
|
Stocks 3 |
2,029 | — | — | — | 2,029 | ||||||||||||
|
Municipal bonds |
— | 790 | — | — | 790 | ||||||||||||
|
Corporate bonds 4 |
— | 346 | — | — | 346 | ||||||||||||
|
U.S. government and agency securities |
215 | 73 | — | — | 288 | ||||||||||||
|
Short-term investments, primarily cash equivalents 5 |
1 | 31 | — | — | 32 | ||||||||||||
|
Subtotal of nuclear decommissioning trusts |
2,245 | 1,240 | — | — | 3,485 | ||||||||||||
|
Total assets 6 |
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 | ||||||
14
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 earnings 1 |
18 | (18 | ) | 18 | 27 | |||||||||
|
Included in regulatory assets and liabilities 2 |
(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 period 3 |
$ | (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.
15
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 | |||||
16
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 AgreementsLong-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%.
17
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 ActivitiesElectric 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 | ||||||
18
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 received 1 |
(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 received 1 |
(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 Activity
1
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 11—Accumulated 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
Note 7. Income Taxes
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision 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 related 1 |
— | (138 | ) | — | (138 | ) | |||||||||
|
Change in tax accounting method for asset removal costs 2 |
— | (40 | ) | — | (40 | ) | |||||||||
|
State tax – net of federal benefit |
4 | 16 | 13 | 23 | |||||||||||
|
Health care legislation 3 |
— | — | — | 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 | |||||||||
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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.
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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 expense 1 |
$ | 11 | $ | 9 | $ | 17 | $ | 17 | ||||||
|
Income tax benefits related to stock compensation expense |
5 | 4 | 7 | 7 | ||||||||||
|
Excess tax benefits 2 |
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.
29
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 "—Contingencies—Midwest 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 "—Contingencies—Homer City New Source Review and Other Litigation."
30
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.
31
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
32
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.
33
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.
34
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 ("SO 2 ") emissions and annual ozone season nitrogen oxide ("NO x ") 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 SO 2 emissions.
CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO 2 or NO x emissions from operations will need to be matched by a sufficient amount of SO 2 or NO x allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO 2 and NO x 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 SO 2 and NO x 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 SO 2 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 SO 2 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 SO 2 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 SO 2 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 SO 2 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 SO 2 and particulate emissions control equipment for Units 1 and 2. While the Phase II SO 2 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 SO 2 controls at Units 1 and 2. The installation of those SO 2 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 SO 2 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
35
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
36
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 LossEdison 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.
37
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 | |||||||
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.
38
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 ExpensesOther 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
Note 17. Business Segments
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 other 2 |
(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 generation 1 |
(31 | ) | 27 | (51 | ) | 104 | |||||||
|
Parent and other 2 |
(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 other 2 |
(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 | ) | |||||||||||
|
Edison International Parent and Other |
(4 | ) | (11 | ) | 7 | (6 | ) | (16 | ) | 10 | |||||||||||
|
Edison International Consolidated |
$ | 177 | $ | 205 | $ | (28 | ) | $ | 379 | $ | 473 | $ | (94 | ) | |||||||
Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings by principal operating subsidiary internally for financial planning and for analysis of performance. Core earnings (losses) by principal operating subsidiary are also used when communicating with analysts and investors regarding our earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including lease terminations, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings.
SCE's 2011 core earnings decreased $37 million and $18 million for the quarter and year-to-date, respectively. Core earnings decreased as rate base growth was more than offset by higher income tax expense, including a $40 million benefit in the second quarter of 2010 from a change in tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program.
EMG's 2011 core earnings increased $2 million and decreased $86 million for the quarter and year-to-date, respectively. Results for the year-to-date were impacted by the Homer City outage, lower realized energy prices, higher plant maintenance expenses and lower trading income. In addition, unrealized gains were $5 million for the first six months of 2011 compared to unrealized losses of $17 million in the same period last year.
44
Consolidated non-core items for Edison International included:
During the first six months of 2011, SCE's capital investment program focused on upgrading and expanding SCE's transmission and distribution system; replacing generation asset equipment; and installing smart meters. Total capital expenditures (including accruals) were $1.6 billion during the first six months of 2011 compared to $1.5 billion during the same period in 2010.
SCE continues to project that 2011 capital investments will be in the range of $3.9 billion to $4.4 billion and that 2011 – 2014 total capital investment spending will be in the range of $15.6 billion to $17.5 billion. Actual capital spending will be affected by regulatory approval, permitting, market and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2010 MD&A.
In July 2011, the FERC adopted new rules that remove incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities. The rules direct regional entities, such as ISOs, to create new processes that would allow other providers to develop new transmission projects. The new processes will not become effective until approved by FERC, which is expected in late 2012. The majority of SCE's 2011 - 2014 transmission capital forecast relates to transmission projects that have been approved by the CAISO and barring a re-evaluation under the new rules, will not be subject to the new processes. The impact of the new rules on future transmission projects will depend on the processes ultimately implemented by regional entities.
As discussed in the year-ended 2010 MD&A, SCE filed its GRC application in November 2010. In July 2011, SCE submitted rebuttal testimony in response to intervenor recommendations and updated its requested 2012 base rate revenue requirement to $6.2 billion to reflect agreement on certain issues identified in intervenor testimony. SCE's updated request, after considering the effects of sales growth, would result in incremental customer base rate increases of $794 million, $155 million and $515 million in 2012, 2013 and 2014, respectively. The updated request also reflects a previously submitted base revenue requirement reduction of $38 million, $133 million and $145 million in 2012, 2013, and 2014, respectively, primarily due to a reduction in rate base from inclusion of higher deferred income taxes resulting from bonus depreciation deductions under the 2010 Tax Relief Act.
The Division of Ratepayer Advocates ("DRA") recommended that SCE's requested 2012 base rate revenue requirement be decreased by approximately $850 million, comprised of approximately $630 million in operation and maintenance expense reductions and approximately $220 million in capital-related revenue requirement reductions. The Utility Reform Network or TURN and other intervenors recommended an additional $610 million revenue requirement reduction, beyond the DRA adjustments, primarily capital-related in nature, as well as disallowances of recorded capital costs for specific projects. Intervenors have also recommended changes to SCE's proposed post test year ratemaking methodology to be used for 2013 and 2014.
The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. To the extent a final decision is delayed, the CPUC has authorized the establishment of a GRC memorandum account, which will make the revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012. SCE cannot predict the revenue requirement the CPUC will ultimately authorize.
45
In August 2011, the FERC accepted SCE's request to implement a formula rate, effective January 1, 2012, to determine SCE's FERC transmission revenue requirement, including its construction work in progress ("CWIP") incentive revenue requirement that was previously recovered through a separate mechanism, subject to refund and settlement procedures. The FERC reduced SCE's proposed base ROE request from 11.5% to 9.93% (before adding the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives). SCE's request proposed the adoption of a specific formula to calculate a forecast revenue requirement that is used to establish rates and is trued-up annually to allow SCE to recover its actual revenue requirement, including its actual cost of service, actual rate base (including the impact of bonus depreciation) and the authorized return on investment. SCE's request also allows SCE to make single-issue rate filings requesting changes to certain elements of the formula, including the base ROE, depreciation rates and the retail rate structure. The FERC order directs SCE to modify its 2012 forecast transmission revenue requirement of $771 million for the lower base ROE. SCE expects to file a request for rehearing of the adopted base ROE within 30 days and cannot predict the formula rate structure or the base ROE that the FERC will ultimately authorize.
Nuclear Industry and Regulatory Response to Events in Japan
As discussed in the 2010 Form 10-K under the heading "Nuclear Power Plant Regulation," SCE is subject to the jurisdiction of the NRC with respect to its ownership interest in San Onofre and Palo Verde. In light of the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the March 2011 earthquake and tsunami, the NRC has been performing and plans to continue to perform additional operational and safety reviews of nuclear facilities in the United States. The NRC also created a Task Force to conduct a systematic review of U.S. NRC processes and regulations to determine whether additional improvements to the existing nuclear regulatory system are warranted in light of the events in Japan. The Task Force issued its initial report in July 2011, which concluded that a sequence of events like the Fukushima accident is unlikely to occur in the U.S., and that continued operation of U.S. reactors does not pose an imminent risk to public health and safety. The Task Force Report also included several proposed changes to regulations applicable to protection against natural phenomena, including earthquakes and flooding, and emergency preparedness. These recommendations must undergo additional review by NRC management and the nuclear industry before any changes are implemented; if implemented, they may impact future operations and capital requirements at United States nuclear facilities, including the operations and capital requirements of SCE's nuclear facilities.
The profitability of EMG's competitive power generation operations is expected to be significantly lower in 2011 compared to 2010 as a result of lower realized energy prices driven by the expiration of hedge contracts, higher fuel costs and outages at the Homer City plant during the first half of 2011. In addition, the profitability of EMG's Midwest Generation plants is expected to be adversely affected beginning in 2012 by a decline in capacity prices (projected to begin in June 2012) and higher rail transportation costs (due to the expiration at the end of 2011 of a favorable long-term rail contract), and EMG's Homer City plant is expected to be adversely impacted by new environmental regulations discussed further below. As a result, EMG may incur net losses during 2011 and in subsequent years unless energy and capacity prices increase or its costs decline.
At June 30, 2011, EMG and its subsidiaries had $870 million in cash and cash equivalents and $945 million of liquidity available from credit facilities that expire in 2012. EMG's principal subsidiary, EME, had $3.7 billion of senior notes outstanding at June 30, 2011, $500 million of which mature in 2013. EMG's business plans are focused on operating effectively through the current commodity price cycle, environmental compliance and energy project development plans.
Cross-State Air Pollution Rule
On July 6, 2011, the US EPA adopted its final CSAPR which will replace the 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 SO 2 emissions and annual and ozone season NO x emissions in two phases: a first phase effective January 1,
46
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 SO 2 emissions.
CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO 2 or NO x emissions from operations will need to be matched by a sufficient amount of SO 2 or NO x allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO 2 and NO x 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 SO 2 and NO x 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 SO 2 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 SO 2 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 SO 2 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 SO 2 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 SO 2 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 SO 2 and particulate emissions control equipment for Units 1 and 2. While the Phase II SO 2 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 SO 2 controls at Units 1 and 2. The installation of those SO 2 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 SO 2 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.
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, EME does not expect 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.
Homer City does not currently have sufficient capital and does not expect to generate sufficient funds from operations to complete retrofits effectively required by CSAPR Phase II. EME is under no legal obligation to provide funding and has chosen not to. Accordingly, Homer City will need third-party capital to undertake the retrofits required by 2014 under CSAPR. However, restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Consequently, the installation of environmental compliance equipment will be dependent on lessors, holders of the pass-through certificates and new providers of capital funding. Homer City has commenced discussions with
47
its lessors concerning such matters. There can be no assurance that Homer City will be able to raise the financing necessary to install the required SO 2 control equipment in a timely manner or on terms that will not result in a significant dilution of its interest in the Homer City plant.
Failure of Homer City to install the required equipment or determine an economic manner to continue plant operations could result in a loss of its lease and a cessation of plant operations. Cessation of plant operations or a significant reduction of the value of Homer City's interest in the plant could have a material adverse effect on future financial results, cash flow, financial flexibility and assets of EME compared to historical levels. At June 30, 2011, the book value of EME's investment in Homer City was approximately $1.1 billion.
Midwest Generation Environmental Compliance Plans and Costs
During 2011, Midwest Generation continued its permitting and planning activities for NO x and SO 2 controls to meet the requirements of the CPS. Midwest Generation does not anticipate a material change to its current approach in order to comply with CSAPR. Based on its continuing review, EME also does not expect the US EPA issued proposed National Emission Standards for Hazardous Air Pollutants, if adopted, 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. Midwest Generation expects to continue to develop and implement a compliance program that includes the use of activated carbon injection, upgrades to particulate removal systems and dry sorbent injection, combined with its use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NO x and SO 2 as well as for HAPs, such as mercury, acid gas and non-mercury metals. Based on stack tests performed at various Midwest Generation plants, Midwest Generation believes that currently installed activated carbon injection and particulate removal equipment is sufficient to achieve or exceed the mercury standards outlined in the US EPA's existing and proposed rules. Midwest Generation does not anticipate a material change to its current approach in order to comply with CSAPR.
In February 2011, the Illinois EPA issued construction permits authorizing Midwest Generation to install a dry sorbent injection system using Trona or other sodium-based sorbents at the Powerton Station's Units 5 and 6. Midwest Generation had previously received construction permits for dry sorbent injection installation at Waukegan Station's Unit 7.
Decisions regarding whether or not to proceed with retrofitting units to comply with CPS requirements for SO 2 emissions remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to temporarily or permanently shut down units, instead of installing controls, to be in compliance with the CPS.
Therefore, decisions about any particular combination of retrofits and shutdowns Midwest Generation may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others, subject to the requirements of the CPS and other applicable regulations.
In March 2008, Walnut Creek Energy, a subsidiary of EMG, was awarded a 10-year power sales agreement starting in 2013 for the output from its planned Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The contract was issued by SCE, through a competitive bidding process. Construction began on the Walnut Creek project in June 2011. The Walnut Creek project has estimated construction costs of $575 million and is expected to achieve commercial operation in 2013. In July 2011, Walnut Creek Energy completed non-recourse financings to fund the Walnut Creek project. The Walnut Creek construction loans, including the project level and intermediate holding company loans, have an effective interest rate of 3.11% including the impact of interest rate swaps through May 31, 2013. For more information, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Project Financings—Walnut Creek."
Environmental Regulation Developments
For additional discussion of environmental regulation developments regarding proposed Hazardous Air Pollutant Regulations, Cross-State Air Pollution Rule, Once-Through Cooling Issues, Greenhouse Gas Regulation and Greenhouse Gas Litigation Developments, see "Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments."
48
SOUTHERN CALIFORNIA EDISON COMPANY
SCE's results of operations are derived mainly through two sources:
Utility earning activities include base rates that are designed to recover forecasted operation and maintenance costs, certain capital-related carrying costs, interest, taxes and a return, including the return on capital projects recovered through CPUC-authorized mechanisms outside the GRC process. Differences between authorized amounts and actual results impact earnings. Also, included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.
Utility cost-recovery activities include rates that provide for recovery (with no return), subject to review of reasonableness or compliance with upfront standards, of fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses, and depreciation expense related to certain projects.
The following tables summarize SCE's results of operations for the periods indicated. The presentation separately identifies utility earning activities and utility cost-recovery activities.
Three Months Ended June 30, 2011 versus June 30, 2010
|
|
Three months ended
June 30, 2011 |
Three months ended
June 30, 2010 |
||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
||||||||||||||||||||
|
(in millions)
|
Utility
Earning Activities |
Utility
Cost- Recovery Activities |
Total
Consolidated |
Utility
Earning Activities |
Utility
Cost- Recovery Activities |
Total
Consolidated |
||||||||||||||
|
Operating revenue |
$ | 1,383 | $ | 1,063 | $ | 2,446 | $ | 1,308 | $ | 939 | $ | 2,247 | ||||||||
|
Fuel and purchased power |
— | 732 | 732 | — | 706 | 706 | ||||||||||||||
|
Operations and maintenance |
549 | 297 | 846 | 537 | 218 | 755 | ||||||||||||||
|
Depreciation, decommissioning and amortization |
323 | 33 | 356 | 306 | 14 | 320 | ||||||||||||||
|
Property taxes and other |
68 | 1 | 69 | 61 | 1 | 62 | ||||||||||||||
|
Total operating expenses |
940 | 1,063 | 2,003 | 904 | 939 | 1,843 | ||||||||||||||
|
Operating income |
443 | — | 443 | 404 | — | 404 | ||||||||||||||
|
Net interest expense and other |
(89 | ) | — | (89 | ) | (85 | ) | — | (85 | ) | ||||||||||
|
Income before income taxes |
354 | — | 354 | 319 | — | 319 | ||||||||||||||
|
Income tax expense |
128 | — | 128 | 5 | — | 5 | ||||||||||||||
|
Net income |
226 | — | 226 | 314 | — | 314 | ||||||||||||||
|
Dividends on preferred and preference stock |
15 | — | 15 | 13 | — | 13 | ||||||||||||||
|
Net income available for common stock |
$ | 211 | $ | — | $ | 211 | $ | 301 | $ | — | $ | 301 | ||||||||
|
Core Earnings 1 |
$ | 211 | $ | 248 | ||||||||||||||||
|
Non-Core Earnings: |
||||||||||||||||||||
|
Global Settlement |
— | 53 | ||||||||||||||||||
|
Tax impact of health care legislation |
— | — | ||||||||||||||||||
|
Total SCE GAAP Earnings |
$ | 211 | $ | 301 | ||||||||||||||||
49
Utility earning activities were primarily affected by the following:
Utility Cost-Recovery Activities
Utility cost-recovery activities were primarily affected by the following:
50
Six Months Ended June 30, 2011 versus June 30, 2010
|
|
Six months ended
June 30, 2011 |
Six months ended
June 30, 2010 |
||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
||||||||||||||||||||
|
(in millions)
|
Utility
Earning Activities |
Utility
Cost- Recovery Activities |
Total
Consolidated |
Utility
Earning Activities |
Utility
Cost- Recovery Activities |
Total
Consolidated |
||||||||||||||
|
Operating revenue |
$ | 2,746 | $ | 1,932 | $ | 4,678 | $ | 2,573 | $ | 1,833 | $ | 4,406 | ||||||||
|
Fuel and purchased power |
— | 1,317 | 1,317 | — | 1,395 | 1,395 | ||||||||||||||
|
Operations and maintenance |
1,078 | 553 | 1,631 | 1,057 | 411 | 1,468 | ||||||||||||||
|
Depreciation, decommissioning and amortization |
641 | 59 | 700 | 605 | 24 | 629 | ||||||||||||||
|
Property taxes and other |
143 | 3 | 146 | 129 | 1 | 130 | ||||||||||||||
|
Total operating expenses |
1,862 | 1,932 | 3,794 | 1,791 | 1,831 | 3,622 | ||||||||||||||
|
Operating income |
884 | — | 884 | 782 | 2 | 784 | ||||||||||||||
|
Net interest expense and other |
(171 | ) | — | (171 | ) | (157 | ) | (2 | ) | (159 | ) | |||||||||
|
Income before income taxes |
713 | — | 713 | 625 | — | 625 | ||||||||||||||
|
Income tax expense |
251 | — | 251 | 134 | — | 134 | ||||||||||||||
|
Net income |
462 | — | 462 | 491 | — | 491 | ||||||||||||||
|
Dividends on preferred and preference stock |
29 | — | 29 | 26 | — | 26 | ||||||||||||||
|
Net income available for common stock |
$ | 433 | $ | — | $ | 433 | $ | 465 | $ | — | $ | 465 | ||||||||
|
Core Earnings 1 |
$ | 433 | $ | 451 | ||||||||||||||||
|
Non-Core Earnings: |
||||||||||||||||||||
|
Global Settlement |
— | 53 | ||||||||||||||||||
|
Tax impact of health care legislation |
— | (39 | ) | |||||||||||||||||
|
Total SCE GAAP Earnings |
$ | 433 | $ | 465 | ||||||||||||||||
Utility earning activities were primarily affected by the following:
51
Utility Cost-Recovery Activities
Utility cost-recovery activities were primarily affected by the following:
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $2.4 billion and $4.5 billion for the three- and six-month periods ended June 30, 2011, respectively, compared to $2.4 billion and $4.4 billion for the respective periods in 2010. The year-to-date increase reflects a rate increase of $40 million and a sales volume increase of $60 million. The rate increase reflects higher system average rates for 2011 compared to the same period in 2010, primarily due to the implementation of rates authorized in the CPUC 2009 GRC decision and the 2010 FERC rate case. As a result of a CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk or benefit related to retail electricity sales (see "Item 1. Business—Overview of Ratemaking Mechanisms" in the 2010 Form 10-K).
SCE remits to CDWR and does not recognize as revenue the amounts that SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees. The amounts collected and remitted to CDWR were $280 million and $555 million for the three- and six-month periods ended June 30, 2011, respectively, and $286 million and $582 million for the respective periods in 2010. The CDWR-related rates in 2011 continue to reflect an approximately $585 million refund of operating reserves that CDWR can release as their contracts terminate. Total customer rates are expected to increase as CDWR operating reserves are fully refunded. The power contracts that CDWR allocated to SCE will terminate by the end of 2011; however, the refund of operating reserves is expected to continue through 2012. SCE's revenue and related purchased power expense is expected to increase as these CDWR contracts are replaced by power purchase agreements entered into by SCE.
52
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.
|
|
Three months ended
June 30, |
Six months ended
June 30, |
|||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
|||||||||||
|
Income before income taxes |
$ | 354 | $ | 319 | $ | 713 | $ | 625 | |||||||
|
Provision for income tax at federal statutory rate of 35% |
$ | 124 | $ | 112 | $ | 249 | $ | 219 | |||||||
|
Increase (decrease) in income tax from: |
|||||||||||||||
|
Items presented with related state income tax, net |
|||||||||||||||
|
Global settlement related 1 |
— | (53 | ) | — | (53 | ) | |||||||||
|
Change in tax accounting method for asset removal costs 2 |
— | (40 | ) | — | (40 | ) | |||||||||
|
State tax – net of federal benefit |
18 | 19 | 30 | 21 | |||||||||||
|
Health care legislation 3 |
— | — | — | 39 | |||||||||||
|
Property-related and other |
(14 | ) | (33 | ) | (28 | ) | (52 | ) | |||||||
|
Total income tax expense |
$ | 128 | $ | 5 | $ | 251 | $ | 134 | |||||||
|
Effective tax rate |
36% | 2% | 35% | 21% | |||||||||||
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.
For a discussion of the status of Edison International's income tax audits, see "Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes."
LIQUIDITY AND CAPITAL RESOURCES
SCE's ability to operate its business, complete planned capital projects, and implement its business strategy are dependent upon its cash flow and access to the capital markets to finance its activities. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, dividend payments made to Edison International, and the outcome of tax and regulatory matters.
SCE expects to fund its continuing obligations, projected capital expenditures for 2011 and dividends to Edison International through cash and equivalents on hand, operating cash flows, tax benefits and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities if additional funding and liquidity are necessary to meet operating and capital requirements.
As of June 30, 2011, SCE had approximately $46 million of cash and equivalents and short-term investments. SCE had two credit facilities: a $2.4 billion five-year credit facility that matures in February
53
2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that matures in March 2013.
|
(in millions)
|
Credit Facilities
|
|||
|---|---|---|---|---|
|
Commitment |
$ | 2,894 | ||
|
Outstanding borrowings supported by credit facilities |
(200 | ) | ||
|
Outstanding letters of credit |
(71 | ) | ||
|
Amount available |
$ | 2,623 | ||
SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At June 30, 2011, SCE's debt to total capitalization ratio was 0.47 to 1.
The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At June 30, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.7% resulting in the capacity to pay $460 million in additional dividends.
During the first six months of 2011, SCE made $230 million in dividend payments to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the actual level of capital expenditures, operating cash flows and earnings.
Margin and Collateral Deposits
Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of June 30, 2011.
| (in millions) | ||||
|---|---|---|---|---|
|
Collateral posted as of June 30, 2011 1 |
$ | 86 | ||
|
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade |
71 | |||
|
Posted and potential collateral requirements 2 |
$ | 157 | ||
Workers Compensation Self-Insurance Fund
SCE is self-insured for workers compensation claims. SCE assesses workers compensation claims that have been asserted and those that have been incurred but not reported to determine the probable amount of losses that should be recorded. The Department of Industrial Relations for the State of California requires companies that are self-insured for workers compensation to post collateral (in the form of cash and/or letters of credits) based on the estimated workers' compensation liability if a company's bond rating were to fall below "B." As of June 30, 2011, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $201 million for its workers compensation self-insurance plan.
54
Historical Consolidated Cash Flows
Condensed Consolidated Statement of Cash Flows
The table below sets forth condensed historical cash flow information for SCE.
|
|
Six months ended
June 30, |
||||||
|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
|||||
|
Net cash provided by operating activities |
$ | 1,385 | $ | 1,095 | |||
|
Net cash provided by financing activities |
491 | 465 | |||||
|
Net cash used by investing activities |
(2,091 | ) | (1,937 | ) | |||
|
Net decrease in cash and cash equivalents |
$ | (215 | ) | $ | (377 | ) | |
Net Cash Provided by Operating Activities
Net cash provided by operating activities increased $290 million in the first six months of 2011 compared to the first six months of 2010. The increase reflects higher receipts from customers due to increases in authorized revenue and lower tax payments resulting from bonus depreciation. These increases were partially offset by net cash outflows related to regulatory balancing account activities. The operating cash flows were also impacted by the timing of cash receipts and disbursements related to working capital.
Net Cash Provided by Financing Activities
Net cash provided by financing activities for the first six months of 2011 was $491 million consisting of the following significant events:
Net cash provided by financing activities for the first six months of 2010 was $465 million consisting of the following significant events:
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Net Cash Used by Investing Activities
Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $2.0 billion and $1.8 billion for the six months ended June 30, 2011 and 2010, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $84 million and $97 million for the six months ended June 30, 2011 and 2010, respectively.
Contractual Obligations and Contingencies
For a discussion of power purchase commitments, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Third-Party Power Purchase Agreements."
SCE has contingencies related to the Navajo Nation Litigation, nuclear insurance and spent nuclear fuel, which are discussed in "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
As of June 30, 2011, SCE had 24 identified material sites for remediation and recorded an estimated minimum liability of $54 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies" for further discussion.
SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivative instruments, as appropriate, to manage its market risks. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Edison International Notes to Consolidated Financial Statements—Note 6. Derivative and Hedging Activities" and "Note 4. Fair Value Measurements" and see "SCE: Market Risk Exposures—Commodity Price Risk" in the year-ended 2010 MD&A.
The fair value of outstanding derivative instruments used to mitigate SCE's exposure to commodity price risk was a net liability of $532 million and $207 million at June 30, 2011 and December 31, 2010, respectively. For further discussion of fair value measurements and the fair value hierarchy, see "Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."
Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these agreements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual agreements,
56
including master netting agreements. As of June 30, 2011, the amount of balance sheet exposure as described above, by the credit ratings of SCE's counterparties, was as follows:
|
|
June 30, 2011 | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
Exposure
2
|
Collateral
|
Net Exposure
|
||||||||
|
S&P Credit Rating 1 |
|||||||||||
|
A or higher |
$ | 130 | $ | — | $ | 130 | |||||
|
A- |
9 | — | 9 | ||||||||
|
Not rated 3 |
41 | (31 | ) | 10 | |||||||
|
Total |
$ | 180 | $ | (31 | ) | $ | 149 | ||||
The credit risk exposure set forth in the table above is composed of $4 million of net accounts receivable and $176 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.
57
Results of Continuing Operations
This section discusses operating results for the three- and six-month periods ended June 30, 2011 and 2010. EMG's continuing operations include the coal plants, renewable energy and gas-fired projects and energy trading. EMG's discontinued operations include all international operations, except the Doga project.
The following table is a summary of competitive power generation results of operations for the periods indicated.
|
|
Three months ended
June 30, |
Six months ended
June 30, |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||
|
Competitive power generation operating revenues |
$ | 538 | $ | 495 | $ | 1,090 | $ | 1,147 | ||||||
|
Fuel |
174 | 160 | 356 | 374 | ||||||||||
|
Operation and maintenance |
329 | 316 | 610 | 566 | ||||||||||
|
Depreciation and amortization |
79 | 60 | 152 | 120 | ||||||||||
|
Other |
8 | 3 | 8 | 7 | ||||||||||
|
Total operating expenses |
590 | 539 | 1,126 | 1,067 | ||||||||||
|
Operating income (loss) |
(52 | ) | (44 | ) | (36 | ) | 80 | |||||||
|
Interest and dividend income |
27 | 4 | 29 | 24 | ||||||||||
|
Equity in income from unconsolidated affiliates – net |
17 | 20 | 12 | 39 | ||||||||||
|
Other income, net |
3 | 1 | 6 | — | ||||||||||
|
Interest expense |
(80 | ) | (66 | ) | (160 | ) | (133 | ) | ||||||
|
Income (loss) from continuing operations before income taxes |
(85 | ) | (85 | ) | (149 | ) | 10 | |||||||
|
Benefit for income tax |
(55 | ) | (111 | ) | (101 | ) | (86 | ) | ||||||
|
Income (loss) from continuing operations |
(30 | ) | 26 | (48 | ) | 96 | ||||||||
|
Income (loss) from discontinued operations – net of tax |
(1 | ) | 1 | (3 | ) | 8 | ||||||||
|
Net income (loss) |
(31 | ) | 27 | (51 | ) | 104 | ||||||||
|
Less: Net income attributable to noncontrolling interests |
— | — | — | — | ||||||||||
|
Net income (loss) available for common shareholder |
$ | (31 | ) | $ | 27 | $ | (51 | ) | $ | 104 | ||||
|
Core Earnings (Losses) 1 |
$ | (30 | ) | $ | (32 | ) | $ | (48 | ) | $ | 38 | |||
|
Non-Core Earnings (Losses) |
||||||||||||||
|
Global Settlement |
— | 58 | — | 58 | ||||||||||
|
Discontinued Operations |
(1 | ) | 1 | (3 | ) | 8 | ||||||||
|
Total EMG GAAP Earnings (Losses) |
$ | (31 | ) | $ | 27 | $ | (51 | ) | $ | 104 | ||||
EMG's second quarter 2011 core earnings were higher than second quarter 2010 core earnings primarily due to the following pre-tax items:
These increases were partially offset by the following:
58
EMG's core earnings for the six months ended June 30, 2011 were lower than core earnings for the six months ended June 30, 2010 primarily due to the following pre-tax items:
These decreases were partially offset by the following:
Non-core item for EMG included:
Adjusted Operating Income ("AOI")—Overview
The following section and table provide a summary of results of EMG's operating projects and corporate expenses for the second quarters of 2011 and 2010 and six months ended June 30, 2011 and 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.
59
The following table shows the adjusted operating income (loss) of EMG's projects:
|
|
Three months ended
June 30, |
Six months ended
June 30, |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
|||||||||
|
Midwest Generation plants |
$ | (52 | ) | $ | (39 | ) | $ | 3 | $ | 48 | |||
|
Homer City plant 1 |
(10 | ) | — | (26 | ) | 37 | |||||||
|
Renewable energy projects |
24 | 19 | 45 | 29 | |||||||||
|
Energy trading 1 |
41 | 31 | 56 | 78 | |||||||||
|
Big 4 projects |
9 | 12 | 11 | 16 | |||||||||
|
Sunrise |
6 | 7 | (1 | ) | 3 | ||||||||
|
Doga |
26 | — | 26 | 15 | |||||||||
|
March Point 2 |
— | — | — | 17 | |||||||||
|
Westside projects |
(1 | ) | — | (1 | ) | 1 | |||||||
|
Other projects |
6 | 3 | 10 | 6 | |||||||||
|
Leveraged lease income |
2 | 1 | 3 | 2 | |||||||||
|
Other operating income |
2 | 2 | 2 | 1 | |||||||||
|
|
53 | 36 | 128 | 253 | |||||||||
|
Corporate administrative and general |
(33 | ) | (36 | ) | (69 | ) | (74 | ) | |||||
|
Corporate depreciation and amortization |
(6 | ) | (4 | ) | (12 | ) | (8 | ) | |||||
|
AOI 3 |
$ | 14 | $ | (4 | ) | $ | 47 | $ | 171 | ||||
The following table reconciles AOI to operating income as reflected on EMG's consolidated statements of operations:
|
|
Three months ended
June 30, |
Six months ended
June 30, |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||
|
AOI |
$ | 14 | $ | (4 | ) | $ | 47 | $ | 171 | |||||
|
Less: |
||||||||||||||
|
Equity in income of unconsolidated affiliates |
17 | 20 | 12 | 39 | ||||||||||
|
Dividend income from projects |
27 | 2 | 28 | 18 | ||||||||||
|
Production tax credits |
19 | 19 | 37 | 33 | ||||||||||
|
Other income, net |
2 | (1 | ) | 5 | 1 | |||||||||
|
Operating Income (Loss) |
$ | (51 | ) | $ | (44 | ) | $ | (35 | ) | $ | 80 | |||
60
Adjusted Operating Income from Consolidated Operations
The following table presents additional data for the Midwest Generation plants:
|
|
Three months ended
June 30, |
Six months ended
June 30, |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||
|
Operating Revenues |
$ | 280 | $ | 281 | $ | 631 | $ | 660 | ||||||
|
Operating Expenses |
||||||||||||||
|
Fuel 1 |
107 | 98 | 233 | 239 | ||||||||||
|
Plant operations |
164 | 167 | 282 | 265 | ||||||||||
|
Plant operating leases |
18 | 18 | 37 | 37 | ||||||||||
|
Depreciation and amortization |
29 | 28 | 58 | 56 | ||||||||||
|
Asset retirements |
9 | 2 | 9 | 3 | ||||||||||
|
Administrative and general |
5 | 7 | 11 | 12 | ||||||||||
|
Total operating expenses |
332 | 320 | 630 | 612 | ||||||||||
|
Operating Income (Loss) |
(52 | ) | (39 | ) | 1 | 48 | ||||||||
|
Other Income |
— | — | 2 | — | ||||||||||
|
AOI |
$ | (52 | ) | $ | (39 | ) | $ | 3 | $ | 48 | ||||
|
Statistics |
||||||||||||||
|
Generation (in GWh) |
5,560 | 5,430 | 13,030 | 13,642 | ||||||||||
AOI from the Midwest Generation plants decreased $13 million for the second quarter ended June 30, 2011, compared to the corresponding period of 2010. The second quarter decrease in AOI was attributable to lower energy revenues, higher fuel costs and higher operating expenses, partially offset by higher capacity revenues. The decline in energy revenues was due to lower average realized energy prices, partially offset by higher generation. The increase in fuel costs was due to higher generation and higher coal costs. The increase in operating expenses was due to higher maintenance and overhauls, including the retirement of equipment that was replaced as part of overhauls.
AOI from the Midwest Generation plants decreased $45 million for six months ended June 30, 2011, compared to the corresponding period of 2010. The 2011 decrease in AOI was attributable to lower energy revenues and higher plant operations costs, partially offset by higher capacity revenues. The decline in energy revenues was due to lower average realized energy prices and lower generation due to the permanent shutdown of Will County Units 1 and 2 at the end of 2010 in accordance with the CPS.
Included in operating revenues were unrealized gains (losses) from hedge activities of $2 million and $(3) million for the second quarters of 2011 and 2010, respectively, and $2 million and $4 million for the six months ended June 30, 2011 and 2010, respectively. Unrealized gains (losses) in 2011 and 2010 were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at the Midwest Generation plants was attributable to changes in the difference between energy prices at the Northern Illinois Hub (the settlement point under forward contracts) and the energy prices at the Midwest Generation plants' busbars (the delivery point where power generated by the Midwest Generation plants is delivered into the transmission system).
Included in fuel costs were unrealized losses of $1 million and $2 million during the second quarters of 2011 and 2010, respectively, and $2 million and $7 million for the six months ended June 30, 2011 and
61
2010, respectively. Unrealized losses were due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into in 2010 and 2009 to hedge variable fuel oil components of rail transportation costs.
The following table presents additional data for the Homer City plant:
|
|
Three months ended
June 30, |
Six months ended
June 30, |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||
|
Operating Revenues 1 |
$ | 136 | $ | 129 | $ | 251 | $ | 304 | ||||||
|
Operating Expenses |
||||||||||||||
|
Fuel 2 |
63 | 57 | 115 | 127 | ||||||||||
|
Plant operations |
50 | 38 | 97 | 75 | ||||||||||
|
Plant operating leases |
26 | 27 | 51 | 52 | ||||||||||
|
Depreciation and amortization |
5 | 4 | 10 | 9 | ||||||||||
|
Asset retirements |
— | 1 | — | 1 | ||||||||||
|
Administrative and general |
2 | 2 | 4 | 3 | ||||||||||
|
Total operating expenses |
146 | 129 | 277 | 267 | ||||||||||
|
Operating Income (Loss) |
(10 | ) | — | (26 | ) | 37 | ||||||||
|
AOI |
$ | (10 | ) | $ | — | $ | (26 | ) | $ | 37 | ||||
|
Statistics |
||||||||||||||
|
Generation (in GWh) |
2,226 | 2,289 | 4,169 | 5,243 | ||||||||||
AOI from the Homer City plant decreased $10 million for the second quarter ended June 30, 2011, compared to the corresponding period of 2010. The second quarter decrease in AOI was attributable to higher plant maintenance costs from outages at Units 1 and 2 and higher coal costs, partially offset by unrealized gains in 2011 compared to unrealized losses in 2010 related to hedge contracts.
AOI from the Homer City plant decreased $63 million for six months ended June 30, 2011, compared to the corresponding period of 2010. The 2011 decrease in AOI was attributable to lower energy revenues driven by lower generation and energy prices, and higher plant maintenance costs from outages at Units 1 and 2, partially offset by unrealized gains in 2011 compared to unrealized losses in 2010 related to hedge contracts and lower fuel costs. The decline in fuel costs was due to lower generation, partially offset by higher coal costs.
Included in operating revenues were unrealized gains (losses) from hedge activities of $2 million and $(12) million for the second quarters of 2011 and 2010, respectively, and $5 million and $(14) million for the six months ended June 30, 2011 and 2010, respectively. Unrealized gains in 2011 were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. Unrealized losses in 2010 were attributable to the ineffective portion of forward and futures contracts. The ineffective portion of hedge contracts at Homer City was attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City plant is delivered into the transmission system).
62
Due to fluctuations in electric demand resulting from warm weather during the summer months and cold weather during the winter months, electric revenues from the coal plants normally vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall), further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, income from the coal plants is seasonal and has significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. For further discussion regarding market prices, see "EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk."
The following table presents additional data for EMG's renewable energy projects:
|
|
Three months ended
June 30, |
Six months ended
June 30, |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||
|
Operating Revenues |
$ | 59 | $ | 34 | $ | 111 | $ | 64 | ||||||
|
Production Tax Credits |
19 | 19 | 37 | 33 | ||||||||||
|
|
78 | 53 | 148 | 97 | ||||||||||
|
Operating Expenses |
||||||||||||||
|
Plant operations |
18 | 12 | 36 | 24 | ||||||||||
|
Depreciation and amortization |
37 | 22 | 68 | 43 | ||||||||||
|
Administrative and general |
1 | — | 2 | 1 | ||||||||||
|
Total operating expenses |
56 | 34 | 106 | 68 | ||||||||||
|
Equity in income (loss) from unconsolidated affiliates |
1 |
— |
1 |
(1 |
) |
|||||||||
|
Other Income |
1 | — | 2 | 1 | ||||||||||
|
AOI 1 |
$ | 24 | $ | 19 | $ | 45 | $ | 29 | ||||||
|
Statistics |
||||||||||||||
|
Generation (in GWh) 2 |
1,555 | 992 | 2,940 | 1,835 | ||||||||||
AOI from renewable energy projects increased $5 million and $16 million in the second quarter and six months ended June 30, 2011, respectively, compared to the corresponding periods of 2010. The 2011 increases were primarily due to projects that achieved commercial operation in late 2010 and 2011 and increased generation at other projects due to higher availability and favorable wind conditions.
EMG seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities primarily in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, coal, and transmission congestion primarily in the eastern U.S. power grid using products available over the counter, through exchanges, and from independent system operators.
63
AOI from energy trading activities increased $10 million and decreased $22 million for the second quarter and six months ended June 30, 2011, compared to the corresponding periods of 2010. The second quarter and year-to-date variances were attributable to fluctuations in revenues from congestion and power trading, compared to the same prior-year periods.
Adjusted Operating Income from Unconsolidated Affiliates
Doga. EMG received a distribution from the Doga project in the second quarter of 2011 and in the first quarter of 2010. AOI is recognized when cash is distributed from the project as the Doga project is accounted for on the cost method.
March Point. During the first quarter of 2010, AOI from the March Point project was $17 million due to an equity distribution received from the project. EMG subsequently sold its ownership interest in the March Point project to its partner in February 2010.
Kern River. Kern River Cogeneration Company has entered into an extension of its power purchase agreement with Southern California Edison Company, which was set to expire in June 2011. EMG expects that this arrangement will eventually be replaced by a new power purchase agreement, but cannot predict whether a new agreement will be reached on acceptable terms or at all.
Seasonality. EMG's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.
|
|
Three months ended
June 30, |
Six months ended
June 30, |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||
|
Interest expense, net of capitalized interest |
||||||||||||||
|
EME debt |
$ | (63 | ) | $ | (58 | ) | $ | (125 | ) | $ | (118 | ) | ||
|
Non-recourse debt |
(17 | ) | (8 | ) | (35 | ) | (15 | ) | ||||||
|
|
$ | (80 | ) | $ | (66 | ) | $ | (160 | ) | $ | (133 | ) | ||
EMG's interest expense increased primarily due to higher debt balances for wind project financing and lower capitalized interest. Capitalized interest for renewable energy projects under construction was $6 million and $16 million for the second quarter and six months ended June 30, 2011, respectively, compared to $12 million and $23 million for the second quarter and six months ended June 30, 2010, respectively.
64
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate:
|
|
Three months ended
June 30, |
Six months ended
June 30, |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||
|
Income (loss) from continuing operations before income taxes |
$ | (85 | ) | $ | (85 | ) | $ | (149 | ) | $ | 10 | |||
|
Provision (benefit) for income taxes at federal statutory rate of 35% |
$ | (30 | ) | $ | (30 | ) | $ | (52 | ) | $ | 4 | |||
|
Increase (decrease) in income tax from: |
||||||||||||||
|
State tax – net of federal provision (benefit) |
(4 | ) | (3 | ) | (9 | ) | 1 | |||||||
|
Tax credits, net |
(19 | ) | (19 | ) | (37 | ) | (34 | ) | ||||||
|
Resolution of 1986-2002 state tax issues |
— | (58 | ) | — | (58 | ) | ||||||||
|
Other |
(2 | ) | (1 | ) | (3 | ) | 1 | |||||||
|
Total income tax benefit |
$ | (55 | ) | $ | (111 | ) | $ | (101 | ) | $ | (86 | ) | ||
|
Effective tax rate |
65% | 131% | 68% | nm* | ||||||||||
* Not meaningful.
For a discussion of the status of Edison International's income tax audits, see "Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes."
LIQUIDITY AND CAPITAL RESOURCES
The following table summarizes available liquidity at June 30, 2011:
|
(in millions)
|
Cash and Cash
Equivalents |
Available
Under Credit Facilities |
Total
Available Liquidity |
||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
|
EME as a holding company |
$ | 237 | $ | 448 | $ | 685 | |||||
|
EME subsidiaries without contractual dividend restrictions |
195 | — | 195 | ||||||||
|
EME corporate cash and cash equivalents |
432 | 448 | 880 | ||||||||
|
EME subsidiaries with contractual dividend restrictions |
|||||||||||
|
Midwest Generation 1 |
254 | 497 | 751 | ||||||||
|
Homer City |
61 | — | 61 | ||||||||
|
Other EME subsidiaries |
86 | — | 86 | ||||||||
|
Other EMG subsidiaries |
37 | — | 37 | ||||||||
|
Total |
$ | 870 | $ | 945 | $ | 1,815 | |||||
EME, as a holding company, does not directly operate any revenue-producing generation facilities. EME relies on cash distributions and tax payments from its projects to meet its obligations, including debt service obligations on long-term debt. The timing and amount of distributions from EME's subsidiaries may be restricted. For further details, see "—Debt Covenants and Dividend Restrictions."
65
The following table summarizes the status of the EME and Midwest Generation credit facilities at June 30, 2011, which mature in June 2012:
|
(in millions)
|
EME
|
Midwest
Generation |
|||||
|---|---|---|---|---|---|---|---|
|
Commitments |
$ | 564 | $ | 500 | |||
|
Outstanding borrowings |
— | — | |||||
|
Outstanding letters of credit |
(116 | ) | (3 | ) | |||
|
Amount available |
$ | 448 | $ | 497 | |||
EME and Midwest Generation may seek to extend or replace credit facilities or retire them by other means. The terms and conditions of any refinancing could be substantially different than those in the current credit facilities. Senior notes in the principal amount of $500 million, which bear interest at 7.50% per annum, are due in June 2013. EME may also from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, open market purchases, privately negotiated transactions or otherwise, depending on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors.
During the first half of 2011, Homer City Units 1 and 2 were off line due to a steam pipe rupture at Unit 1 and precautionary maintenance at Unit 2. While Unit 1 returned to service on April 5, 2011 and Unit 2 on May 25, 2011, the outages and the continuation of low power prices have impacted Homer City's liquidity. As a result, in order to have sufficient working capital available for operating expenses and to pay the equity portion of Homer City's rent payment that was due April 1, 2011 to the owner-lessors, Homer City had to defer certain fuel deliveries, arrange for accelerated payments by EMMT for future energy deliveries under an intercompany arrangement in place between EMMT and Homer City, and draw $12 million from the $20 million equity rent reserve established under its sale-leaseback transaction documents. Homer City must restore the equity rent reserve account and continue to make equity rent payments in order to be entitled to make future distributions. Homer City anticipates that the equity rent reserve balance will be restored in the future. At June 30, 2011, the equity rent reserve balance remained at the drawn balance of $8 million, but Homer City had delivered energy sufficient to eliminate the accelerated payments by EMMT. Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. Accordingly, since April 1, 2011, these revenues have been recorded as part of Homer City's revenues in lieu of their prior classification as EMMT trading revenues. EMMT realized trading revenues of $28 million under this arrangement in 2010.
The actions described above also resulted in Homer City being in compliance with the covenant requirements of its sale-leaseback documents relating to the payment of equity rent at April 1, 2011. Under these documents, rent payments are comprised of two components, senior rent and equity rent. Senior rent is used exclusively for debt service to holders of senior secured bonds issued in connection with the sale-leaseback transaction, while equity rent is paid to the owner-lessors. In order to pay equity rent, among other requirements, Homer City is required to meet historical and projected senior rent service coverage ratios of 1.7 to 1 (subject to reduction to 1.3 to 1 under certain circumstances). Homer City is not subject to any minimum historical and projected senior rent service coverage ratios except as conditions to distributions and equity rent payments. For additional discussion regarding Homer City's liquidity, see "Edison International Management Overview—Management Overview of EMG—Cross-State Air Pollution Rule" and "—Homer City Capital Needs."
66
At June 30, 2011, forecasted capital expenditures through 2013 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:
|
(in millions)
|
July through
December 2011 |
2012
|
2013
|
||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
|
Midwest Generation Plants |
|||||||||||
|
Environmental 1 |
$ | 49 | $ | 172 | $ | 317 | |||||
|
Plant capital |
11 | 21 | 28 | ||||||||
|
Homer City Plant |
|||||||||||
|
Environmental 1 |
— | — | — | ||||||||
|
Plant capital |
5 | 26 | 16 | ||||||||
|
Walnut Creek Project |
173 |
257 |
43 |
||||||||
|
Renewable Energy Projects |
|||||||||||
|
Capital and construction |
72 | — | — | ||||||||
|
Turbine commitments |
45 | 8 | — | ||||||||
|
Other capital |
7 |
14 |
14 |
||||||||
|
Total |
$ | 362 | $ | 498 | $ | 418 | |||||
Environmental Capital Expenditures
Midwest Generation plants' environmental expenditures include $34 million for remaining expenditures in 2011 related to selective non-catalytic reduction (SNCR) equipment and $501 million for expenditures for the remainder of 2011 to 2013 to begin to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO 2 emissions. EMG believes 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 and the proposed National Emissions Standards for Hazardous Air Pollutants. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with CPS and other requirements, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. Accordingly, the environmental expenditures for Midwest Generation in the preceding table represent current projects only and are subject to change based upon a number of considerations. Actual expenditures could be higher or lower. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to continue or complete the project. For additional discussion, see "Edison International Management Overview—Management Overview of EMG—Midwest Generation Environmental Compliance Plans and Costs."
The capital investment plan set forth in the previous table does not include environmental capital expenditures that Homer City will be required to undertake to meet the requirements of CSAPR. The timing, selection of technology and ultimate capital costs remain uncertain. For a discussion of environmental regulations, see "Edison International Management Overview—Management Overview of EMG—Cross State Air Pollution Rule" and "—Homer City Capital Needs" in this MD&A, and "Item 1. Environmental Regulation of Edison International and Subsidiaries" and "Item 1A. Risk Factors—Risks Relating to EMG—Regulatory and Environmental Risks" in the 2010 Form 10-K.
Plant capital expenditures in the preceding table relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, generator stator rewinds, and development of a coal-cleaning plant refuse site and a new ash disposal site.
67
Funding of Capital Expenditures
In July, EME secured $495 million in construction and term financing for the Walnut Creek project. In addition, EME used the proceeds of the Laredo Ridge U.S. Treasury grant of $57 million received in July 2011 to repay the Laredo Ridge bridge loan. EME anticipates that the capital investment for renewable energy projects under construction will be funded using a combination of construction and term financings, U.S. Treasury grants and cash on hand. In addition to the U.S. Treasury grant received in July, U.S. Treasury grants of approximately $360 million are anticipated in 2011 and 2012 based on estimated eligible construction costs for renewable projects. For additional information on the Walnut Creek project, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Project Financings—Walnut Creek."
In the second quarter of 2011, EMG acquired and commenced construction on the 55 MW Pinnacle wind project. The Community Wind North wind project achieved commercial operation on May 28, 2011, and the Taloga wind project achieved commercial operation on July 13, 2011.
The capital investment plan set forth in the previous table does not include capital expenditures for future projects. At June 30, 2011, EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 3,900 MW. The development pipeline represents potential wind projects with respect to which EMG either owns the project rights or has exclusive acquisition rights. The pace of additional growth in EMG's renewable program will be subject to the availability of third-party equity capital. At June 30, 2011, EMG had capitalized costs and turbine deposits totaling $53 million related to renewable energy development efforts. To the extent that the renewable energy projects are not successful, EMG would record a charge to write down the carrying amount of these assets.
The table below sets forth condensed historical cash flow information for EMG.
Condensed Statement of Cash Flows
|
|
Six months ended
June 30, |
||||||
|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
|||||
|
Operating cash flow from continuing operations |
$ | (79 | ) | $ | (120 | ) | |
|
Operating cash flow from discontinued operations |
(3 | ) | 8 | ||||
|
Net cash used by operating activities |
(82 | ) | (112 | ) | |||
|
Net cash provided (used) by financing activities |
96 | (52 | ) | ||||
|
Net cash used by investing activities |
(242 | ) | (274 | ) | |||
|
Net decrease in cash and cash equivalents |
$ | (228 | ) | $ | (438 | ) | |
Net Cash Provided by Operating Activities
The decrease in the first six months of 2011 as compared to the first six months of 2010 in cash used by operating activities from continuing operations was primarily attributable to lower net income, a $253 million deposit paid by Edison Capital to the IRS in 2010 related to the Global Settlement, $92 million of U.S. Treasury grants received in 2010, and changes in other current liabilities.
Net Cash Provided by Financing Activities
The increase in the first six months of 2011 as compared to the first six months of 2010 in cash provided by financing activities from continuing operations was primarily attributable to additional wind project borrowings.
68
Net Cash Provided by Investing Activities
Cash used in investing activities for the first six months of 2011 and 2010 primarily consisted of capital expenditures. In addition, cash used in investing activities for the first six months of 2011 included wind and gas project investments and other capital expenditures.
Credit ratings for EME, Midwest Generation and EMMT as of June 30, 2011 were as follows:
|
|
Moody's Rating
|
S&P Rating
|
Fitch Rating
|
||||
|---|---|---|---|---|---|---|---|
|
EME 1 |
Caa1 | B- | CCC | ||||
|
Midwest Generation 2 |
Ba3 | B+ | BB- | ||||
|
EMMT |
Not Rated | B- | Not Rated | ||||
On June 29, 2011, Moody's lowered the credit ratings of EME to Caa1 from B3 and Midwest Generation to Ba3 from Ba2. On June 30, 2011, Fitch lowered the credit ratings of EME to CCC from B- and Midwest Generation to BB- from BB. All the above ratings are on negative outlook. EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.
EMG does not have any "rating triggers" contained in subsidiary financings that would result in a requirement to make equity contributions or provide additional financial support to its subsidiaries, including EMMT. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party.
For a discussion of the effect of EMMT's credit rating on EMG's ability to sell forward the output of the Homer City plant through EMMT, refer to "EMG: Liquidity and Capital Resources—Credit Ratings—Credit Rating of EMMT" in the year-ended 2010 MD&A.
Margin, Collateral Deposits and Other Credit Support for Energy Contracts
To reduce its exposure to market risk, EME hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities; however, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, and unrealized gains in connection with these hedging and trading activities. For further details, see "Edison International Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."
Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2011, if wholesale energy prices change or if EMMT enters into additional transactions. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—Debt Covenants and Dividend Restrictions."
69
Debt Covenants and Dividend Restrictions
Credit Facility Financial Ratios
EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility.
The following table sets forth the interest coverage ratio:
|
|
Twelve months ended | ||||||
|---|---|---|---|---|---|---|---|
|
|
June 30,
2011 |
December 31,
2010 |
|||||
|
Ratio |
1.83 | 2.07 | |||||
|
Covenant threshold (not less than) |
1.20 | 1.20 | |||||
The following table sets forth the corporate-debt-to-capital ratio:
|
|
June 30,
2011 |
December 31,
2010 |
|||||
|---|---|---|---|---|---|---|---|
|
Corporate-debt-to-capital ratio |
0.52 | 0.52 | |||||
|
Covenant threshold (not more than) |
0.75 | 0.75 | |||||
Key Ratios of EMG's Principal Subsidiaries Affecting Dividends
Set forth below are key ratios of EMG's principal subsidiaries required by financing arrangements at June 30, 2011 or for the 12 months ended June 30, 2011:
|
Subsidiary
|
Financial Ratio
|
Covenant
|
Actual
|
|||||
|---|---|---|---|---|---|---|---|---|
|
Midwest Generation (Midwest Generation plants) |
Debt to Capitalization Ratio |
Less than or equal to 0.60 to 1 |
0.14 to 1 | |||||
|
Homer City (Homer City plant) |
Senior Rent Service Coverage Ratio |
Greater than 1.7 to 1 |
1.75 to 1 | |||||
To make distributions, including repayment of certain intercompany loans, Homer City must meet the senior rent service coverage ratio. In addition, Homer City is restricted from making distributions until the Homer City equity reserve account is replenished. For additional information, see "Edison Mission Group—Liquidity and Capital Resources—Homer City Outage" in this MD&A.
For a more detailed description of the covenants binding EMG's principal subsidiaries that may restrict the ability of those entities to make distributions to EMG directly or indirectly through the other holding companies owned by EMG, refer to "EMG: Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions" in the year ended 2010 MD&A.
EME's Senior Notes and Guaranty of Powerton-Joliet Leases
EME is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At June 30, 2011, the maximum permissible sale or disposition of EME assets was $888 million.
This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above, are retained as cash or cash equivalents or are used to repay debt.
70
Contractual Obligations and Contingencies
For a discussion of fuel supply contracts, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments."
For a discussion of capital expenditures, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments—Capital Expenditures."
Midwest Generation New Source Review and Other Litigation
For a discussion of the Midwest Generation New Source Review lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review and Other Litigation."
Homer City New Source Review and Other Litigation
For a discussion of the Homer City New Source Review lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies—Homer City New Source Review and Other Litigation."
Off-Balance Sheet Transactions
For a discussion of EMG's off-balance sheet transactions, refer to "EMG: Liquidity and Capital Resources—Off-Balance Sheet Transactions" in the year ended 2010 MD&A. There have been no significant developments with respect to EMG's off-balance sheet transactions that affect disclosures presented in the 2010 Form 10-K.
For a detailed discussion of EMG's market risk exposures, including commodity price risk, credit risk and interest rate risk, refer to "EMG: Market Risk Exposures" in the year ended 2010 MD&A.
EMG classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that qualify for hedge accounting) as part of operating revenues or fuel costs. The following table summarizes unrealized gains (losses) from non-trading activities:
|
|
Three months ended
June 30, |
Six months ended
June 30, |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||
|
Midwest Generation plants |
||||||||||||||
|
Non-qualifying hedges |
$ | 2 | $ | (4 | ) | $ | 1 | $ | (6 | ) | ||||
|
Ineffective portion of cash flow hedges |
(1 | ) | (1 | ) | (1 | ) | 3 | |||||||
|
Homer City plant |
||||||||||||||
|
Non-qualifying hedges |
2 | — | 3 | — | ||||||||||
|
Ineffective portion of cash flow hedges |
— | (12 | ) | 2 | (14 | ) | ||||||||
|
Total unrealized gains (losses) |
$ | 3 | $ | (17 | ) | $ | 5 | $ | (17 | ) | ||||
At June 30, 2011, cumulative unrealized gains of $8 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($3 million for the remainder of 2011 and $5 million for 2012).
71
In determining the fair value of EMG's derivative positions, EMG uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EMG's derivative instruments, see "Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements" and "Note 6. Derivative Instruments and Hedging Activities," respectively.
Energy and capacity from the coal plants are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub, and to a lesser extent, the AEP/Dayton and Cinergy Hubs, all in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City plant. In addition, energy hedging transactions may be entered into using natural gas. Energy from 428 MW of merchant renewable energy projects is sold in the energy markets, primarily at spot prices in PJM and the Electric Reliability Council of Texas (ERCOT).
The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first six months of 2011 and 2010:
|
|
24-Hour Average
Historical Market Prices 1 |
|||||||
|---|---|---|---|---|---|---|---|---|
|
|
2011
|
2010
|
||||||
|
Midwest Generation plants |
||||||||
|
Northern Illinois Hub |
$ | 34.50 | $ | 33.44 | ||||
|
Homer City plant |
||||||||
|
PJM West Hub |
46.52 | 43.88 | ||||||
|
Homer City Busbar |
42.45 | 38.28 | ||||||
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at June 30, 2011:
|
|
24-Hour Forward Energy Prices 1 | |||||||
|---|---|---|---|---|---|---|---|---|
|
|
Northern
Illinois Hub |
PJM West Hub
|
||||||
|
2011 |
||||||||
|
July |
$ | 36.43 | $ | 51.14 | ||||
|
August |
38.60 | 51.32 | ||||||
|
September |
29.83 | 43.39 | ||||||
|
October |
26.21 | 40.24 | ||||||
|
November |
29.67 | 40.84 | ||||||
|
December |
31.33 | 46.46 | ||||||
|
2012 calendar "strip" 2 |
33.08 |
46.01 |
||||||
Forward market prices at the Northern Illinois Hub and PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by
72
the coal plants into these markets may vary materially from the forward market prices set forth in the preceding table.
EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services contracts and forward contracts accounted for on the accrual basis) at June 30, 2011 for electricity expected to be generated during the remainder of 2011 and in 2012 and 2013:
|
|
2011 | 2012 | 2013 | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
MWh (in
thousands) |
Average
price/ MWh 1 |
MWh (in
thousands) |
Average
price/ MWh 1 |
MWh (in
thousands) |
Average
price/ MWh 1 |
||||||||||||||
|
Midwest Generation plants 2 |
||||||||||||||||||||
|
Northern Illinois |
6,892 | $ | 38.70 | 7,798 | $ | 37.38 | 1,020 | $ | 39.11 | |||||||||||
|
Homer City plant 3, 4 |
||||||||||||||||||||
|
PJM West Hub |
2,002 | 56.34 | 1,340 | 51.66 | 204 | 51.85 | ||||||||||||||
|
Total |
8,894 | 9,138 | 1,224 | |||||||||||||||||
The following table summarizes the status of capacity sales for Midwest Generation and Homer City at June 30, 2011:
|
|
|
|
|
|
|
Other Capacity Sales,
Net of Purchases 3 |
|
|||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
|
RPM Capacity
Sold in Base Residual Auction |
|
|||||||||||||||||||||
|
|
Installed
Capacity MW |
Unsold
Capacity 1 MW |
Capacity
Sold 2 MW |
|
Average
Price per MW-day |
Aggregate
Average Price per MW-day |
||||||||||||||||||||
|
|
MW
|
Price per
MW-day |
MW
|
|||||||||||||||||||||||
|
July 1, 2011 to May 31, 2012 |
||||||||||||||||||||||||||
|
Midwest Generation |
5,477 | (495 | ) | 4,982 | 4,582 | $ | 110.00 | 400 | $ | 85.00 | $ | 107.99 | ||||||||||||||
|
Homer City |
1,884 | (163 | ) | 1,721 | 1,771 | 110.00 | (50 | ) | 30.00 | 112.32 | ||||||||||||||||
|
June 1, 2012 to May 31, 2013 |
||||||||||||||||||||||||||
|
Midwest Generation |
5,477 | (773 | ) | 4,704 | 4,704 | 16.46 | — | — | 16.46 | |||||||||||||||||
|
Homer City |
1,884 | (232 | ) | 1,652 | 1,736 | 133.37 | (84 | ) | 16.46 | 139.31 | ||||||||||||||||
|
June 1, 2013 to May 31, 2014 |
||||||||||||||||||||||||||
|
Midwest Generation |
5,477 | (827 | ) | 4,650 | 4,650 | 27.73 | — | — | 27.73 | |||||||||||||||||
|
Homer City |
1,884 | (104 | ) | 1,780 | 1,780 | 226.15 | — | — | 221.03 | 4 | ||||||||||||||||
|
June 1, 2014 to May 31, 2015 |
||||||||||||||||||||||||||
|
Midwest Generation |
5,477 | (852 | ) | 4,625 | 4,625 | 125.99 | — | — | 125.99 | |||||||||||||||||
|
Homer City |
1,884 | (190 | ) | 1,694 | 1,694 | 136.50 | — | — | 136.50 | |||||||||||||||||
73
The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 and June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the prices of $16.46 per MW-day and $27.73 per MW-day were substantially lower than other areas' capacity prices. The impact of lower capacity prices for these periods compared to previous years will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices.
During the six months ended June 30, 2011 and 2010, prices at the Homer City busbar were lower than the PJM West Hub by an average of 9% and 13%, respectively, due to transmission congestion in PJM. During the six months ended June 30, 2011, prices at the individual busbars of the Midwest Generation plants were lower than the AEP/Dayton Hub, Cinergy Hub and Northern Illinois Hub by an average of 13%, 2% and 1%, respectively, compared to 11%, 2% and 1%, respectively, during the six months ended June 30, 2010, due to transmission congestion in PJM.
Coal and Transportation Price Risk
The Midwest Generation plants and Homer City plant purchase coal primarily from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at June 30, 2011 for the remainder of 2011 and the following two years:
|
|
Amount of Coal Under Contract
in Millions of Equivalent Tons 1 |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|
|
|
July through
December 2011 |
2012
|
2013
|
|||||||
|
Midwest Generation plants 2 |
8.9 | 11.7 | — | |||||||
|
Homer City plant |
2.7 | 2.2 | 0.8 | |||||||
EMG is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which are related to the price of coal purchased for the Homer City plant, increased during 2011 from 2010 year-end prices. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO 2 per MMBtu sulfur content) increased to a price of $78.20 per ton at July 1, 2011, compared to a price of $70 per ton at December 31, 2010, as reported by the Energy Information Administration.
Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO 2 per MMBtu sulfur content) purchased for the Midwest Generation plants fluctuated between $12.35 per ton and $14.75 per ton during the first six months of 2011. The market price of PRB coal decreased to a price of $13.25 per ton at July 1, 2011, compared to a price of $13.60 per ton at December 31, 2010, as reported by the Energy Information Administration.
EMG has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through December 31, 2011. EMG is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are materially higher than the existing rates under contract. Transportation costs are approximately half of the delivered cost of PRB coal to the Midwest Generation plants.
Emission Allowances Price Risk
The federal Acid Rain Program requires electric generating stations to hold SO 2 allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the CAIR, which expires on December 31, 2011, coal plants are required to hold seasonal and annual NO x allowances.
74
In the event that actual emissions required are greater than allowances held, EMG is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO 2 allowances decreased to $7 per ton during the six months ended June 30, 2011 from $50 per ton in 2010. The average purchase price of annual NO x allowances decreased to $244 per ton during the six months ended June 30, 2011 from $936 per ton in 2010. Based on broker's quotes and information from public sources, the spot price for SO 2 allowances and annual NO x allowances was $4 per ton and $147.50 per ton, respectively, at June 30, 2011.
Under CSAPR, beginning January 1, 2012, the amount of SO 2 that a plant emits in its operation will need to be matched by a sufficient amount of SO 2 allowances designated under this program (CSAPR SO 2 allowances) that are either allocated to the plant under the CSAPR program or purchased in the open market. SO 2 allowances under the federal Acid Rain Program cannot be used to satisfy the requirements under CSAPR. EME will be impacted by market prices for additional CSAPR SO 2 allowances required, but availability and market prices are uncertain. For additional information on CSAPR, see "Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments—Cross-State Air Pollution Rule."
The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EMG's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At June 30, 2011, the balance sheet exposure as described above, by the credit ratings of EMG's counterparties, was as follows:
|
|
June 30, 2011 | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
|
(in millions)
|
Exposure
2
|
Collateral
|
Net Exposure
|
||||||||
|
Credit Rating 1 |
|||||||||||
|
A or higher |
$ | 123 | $ | — | $ | 123 | |||||
|
A- |
2 | — | 2 | ||||||||
|
BBB+ |
16 | — | 16 | ||||||||
|
BBB |
1 | — | 1 | ||||||||
|
BBB- |
14 | — | 14 | ||||||||
|
Below investment grade |
32 | (31 | ) | 1 | |||||||
|
Total |
$ | 188 | $ | (31 | ) | $ | 157 | ||||
The credit risk exposure set forth in the above table is composed of $113 million of net accounts receivable and payables and $76 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EMG's subsidiaries have posted a $50 million cash margin in the aggregate with PJM, NYISO, Midwest Independent Transmission System Operator (MISO), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EMG to credit risk of the related entities.
The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 66% of EMG's consolidated operating revenues for the six months ended June 30, 2011. At June 30, 2011, EMG's account receivable due from PJM was $73 million.
EMG's wind turbine supply agreements contain significant suppliers' obligations related to the manufacturing and delivery of turbines, and payments, for delays in delivery and for failure to meet performance obligations and warranty agreements. EMG's reliance on these contractual provisions is
75
subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to EMG's turbine suppliers may have a material impact on EMG's wind projects and development efforts.
Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EMG mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. For details, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements," and refer to "Note 5 Debt and Credit Agreements" in Item 8 of Edison International's 2010 Form 10-K.
76
EDISON INTERNATIONAL PARENT AND OTHER
Results of operations for Edison International Parent and Other includes amounts from other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.
Edison International Parent and Other income (loss) from continuing operations was $(4) million and $16 million for the three months ended June 30, 2011 and 2010, respectively, and $(6) million and $11 million for the six months ended June 30, 2011 and 2010, respectively. Results for the three- and six-month periods ended June 30, 2010 included $27 million of consolidated tax benefits from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement. Results for the three- and six-month periods ended June 30, 2011 included consolidated tax benefits resulting from differences in state tax allocations to subsidiaries of income taxes under the tax allocation agreements of $5 million and $11 million, respectively.
LIQUIDITY AND CAPITAL RESOURCES
Edison International Parent liquidity and its ability to pay operating expenses and dividends to common shareholders is dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets.
At June 30, 2011, Edison International (parent) had $19 million of cash and equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at June 30, 2011:
|
(in millions)
|
Edison
International (parent) |
|||
|---|---|---|---|---|
|
Commitment |
$ | 1,426 | ||
|
Outstanding borrowings |
(79 | ) | ||
|
Outstanding letters of credit |
— | |||
|
Amount available |
$ | 1,347 | ||
Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. At June 30, 2011, Edison International's consolidated debt to total capitalization ratio was 0.54 to 1.
Condensed Statement of Cash Flows
The table below sets forth condensed historical cash flow information for Edison International Parent and Other.
|
|
Six months ended
June 30, |
||||||
|---|---|---|---|---|---|---|---|
|
(in millions)
|
2011
|
2010
|
|||||
|
Net cash used by operating activities |
$ | (81 | ) | $ | (21 | ) | |
|
Net cash provided by financing activities |
79 | 25 | |||||
|
Net cash provided by investing activities |
1 | 7 | |||||
|
Net increase (decrease) in cash and cash equivalents |
$ | (1 | ) | $ | 11 | ||
77
Net Cash Used by Operating Activities
Net cash used by operating activities primarily relates to interest, operating costs and income taxes of Edison International (parent). In addition to these factors, Edison International funded a portion of the 2011 tax-allocation payments due by Edison Capital in consideration of an intercompany note receivable.
Net Cash Provided (Used) by Financing Activities
Financing activities for the first six months of 2011 were as follows:
Financing activities for the first six months of 2010 were as follows:
78
EDISON INTERNATIONAL (CONSOLIDATED)
LIQUIDITY AND CAPITAL RESOURCES
Significant changes with respect to Edison International (Consolidated) contractual obligations since the filing of the 2010 Form 10-K are discussed in "EMG: Liquidity and Capital Resources—Contractual Obligations and Contingencies" and "SCE: Liquidity and Capital Resources—Contractual Obligations and Contingencies."
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
For a discussion of Edison International's critical accounting estimates and policies, see "Critical Accounting Estimates and Policies" in the year ended 2010 MD&A.
New accounting guidance is discussed in "Edison International Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKInformation responding to this item is included in the MD&A under the headings "SCE: Market Risk Exposures" and "EMG: Market Risk Exposures" and is incorporated herein by reference.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Edison International's management, under the supervision and with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of Edison International's disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, Edison International's disclosure controls and procedures are effective.
PART II. OTHER INFORMATIONFor a discussion of Edison International's legal proceedings, refer to "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies" in the 2010 Form 10-K. There have been no significant developments with respect to legal proceedings specifically affecting Edison International since the filing of the 2010 Form 10-K, except as follows:
California Coastal Commission Potential Environmental Proceeding
In May 2010, the California Coastal Commission issued an NOV to SCE, its contractor, and property owners ("NOV Recipients") related to activity on a property that was used for equipment storage related to a nearby SCE electricity line undergrounding construction project. The NOV alleged that SCE, through its contractor, violated the California Coastal Act by removing without the appropriate permits approximately one acre of vegetation from the property, which was located in a protected coastal zone within and adjacent to the City of Newport Beach, California. In late 2010, SCE tendered an indemnification claim to its contractor for liability associated with the NOV, which the contractor accepted. In April 2011, the NOV Recipients entered into a Consent Order with the Coastal Commission to resolve the NOV Recipients' liability to the Coastal Commission under the Coastal Act. On June 10, 2011, the NOV Recipients entered into a Settlement Agreement to resolve any remaining claims among themselves pertaining to the NOV.
79
Developments related to the Navajo Nation litigation are discussed in "SCE Notes to Consolidated Financial Statements Note 9. Commitments and Contingencies—Contingencies—Navajo Nation Litigation."
Midwest Generation New Source Review and Other Litigation
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 Company 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 on 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.
Homer City New Source Review and Other Litigation
In April 2011, Homer City filed motions to dismiss two complaints that were filed in January 2011 by the US EPA and two residents, respectively, in the Western District of Pennsylvania.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
|
Period
|
(a) Total
Number of Shares (or Units) Purchased 1 |
(b) Average Price
Paid per Share (or Unit) 1 |
(c) Total
Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs |
(d) Maximum
Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
April 1, 2011 to April 30, 2011 |
107,173 | $ | 38.13 | — | — | ||||||||
|
May 1, 2011 to May 31, 2011 |
621,653 | $ | 39.57 | — | — | ||||||||
|
June 1, 2011 to June 30, 2011 |
511,001 | $ | 38.89 | — | — | ||||||||
|
Total |
1,239,827 | $ | 39.17 | — | — | ||||||||
80
| 10.1 | Edison International and Southern California Edison Company Director Compensation Schedule, as adopted June 23, 2011 | ||
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|
10.2 |
|
Edison International 2007 Performance Incentive Plan, Amended and Restated as of February 24, 2011 (File 1-9936, filed as Exhibit 10.1 to Edison International's Form 8-K dated April 28, 2011 and filed April 29, 2011)* |
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31.1 |
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Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act |
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31.2 |
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Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act |
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32 |
|
Statement Pursuant to 18 U.S.C. Section 1350 |
|
|
101 |
|
Financial statements from the quarterly report on Form 10-Q of Edison International for the quarter ended June 30, 2011, filed on August 4, 2011, formatted in XBRL: (i) the Consolidated Statements of Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to the Consolidated Financial Statements |
81
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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|
EDISON INTERNATIONAL
(Registrant) |
|||
|
|
By: |
/s/ Mark C. Clarke
Mark C. Clarke Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer) |
||
Date: August 4, 2011
82
No information found
* THE VALUE IS THE MARKET VALUE AS OF THE LAST DAY OF THE QUARTER FOR WHICH THE 13F WAS FILED.
| FUND | NUMBER OF SHARES | VALUE ($) | PUT OR CALL |
|---|
| DIRECTORS | AGE | BIO | OTHER DIRECTOR MEMBERSHIPS |
|---|---|---|---|
Mr. O’Toole provides public company chief executive leadership experience in a regulated, capital-intensive industry. His operational experience in safety, risk management and crisis management are particularly relevant to the oversight of our business and strategy and his leadership role as Chair of the Safety and Operations Committee. Mr. O’Toole brings extensive safety expertise through his work experience and as a director of the National Safety Council, and has been recognized as a safety leader in both the United States and internationally. He has decades of direct management experience of a large workforce in industries where worker and public safety are critical. | |||
Mr. Taylor provides finance and public policy experience, which is particularly relevant to the Company’s infrastructure investment strategy and highly regulated business. He also brings capital markets experience from his investment banking career. At the University of California, Mr. Taylor had direct responsibility for risk management, accounting and financial reporting. He also brings safety experience from his years as a senior executive of the University of California, which launched the “Be Smart About Safety” campaign across all campuses during his tenure, and in his oversight role as a member of the Board of Trustees of the California State University. As a California resident with extensive professional experience in the state, Mr. Taylor also understands the perspective of utility customers impacted by California’s wildfires and regulatory environment. Mr. Taylor’s leadership qualities, capital markets experience, public policy insights and understanding of the Company’s strategy, business and regulatory landscape provide value as independent Chair of the Board. | |||
Mr. Pizarro provides in-depth knowledge of the Company’s business, experienced industry leadership, safety and operations, workforce management, cybersecurity and technology, business resiliency and strategic planning experience and background. His leadership and experience dealing with difficult challenges at EIX, SCE and Edison Mission Energy (“EME”) add value to the Board. Mr. Pizarro also brings the experience and perspective of a director of several industry-related associations. | |||
Ms. Reed brings extensive utility operations, safety, energy policy and ESG experience from her leadership at National Grid, where she was responsible for ensuring safe and reliable electricity and gas distribution services were provided to over six million people throughout Massachusetts. She also directed strategic energy policy development at National Grid supporting broad energy network investment and climate change mitigation initiatives, which is particularly relevant to our strategy and operations in California’s regulatory environment. Ms. Reed also provides financial expertise as a Certified Public Accountant with experience in public accounting and corporate finance. This experience provides additional value to our Audit and Finance and Safety and Operations Committees. | |||
Ms. Stuntz’s utility, environmental law and public policy experience is particularly relevant to the Company’s business. During her time at the U.S. Department of Energy, she held positions that focused on issues related to global climate change and energy-related measures to minimize GHG emissions, key issues that impact the Company. Ms. Stuntz’s corporate governance experience from her prior service on other public company boards and as a member of our Nominating and Governance Committee since 2014 informs her leadership as Committee Chair. She brings ESG and safety experience from her private industry work with utilities and energy companies, as a director of public companies in industries with environmental and safety concerns, and from serving as Chair of our Nominating and Governance Committee and previously serving on our Safety and Operations Committee from 2014 to 2021. | |||
Mr. Trent provides extensive utility operations, strategic planning, legal and safety experience as an executive of one of the largest electric power companies in the U.S., where he had direct management responsibility for the internal audit function, Sarbanes-Oxley processes, financial operations of four electric utilities, and the health and safety of a large workforce. His utility operational experience in, and perspective on, regulation, risk management, safety and cybersecurity are particularly relevant to our business and the regulatory framework in which SCE operates. This experience is particularly valuable to our Audit and Finance and Safety and Operations Committees, and supports his role as the Board’s liaison to the Company’s cybersecurity oversight group (see page 22). | |||
Ms. Granholm brings extensive experience advancing clean energy solutions and deploying zero-carbon technologies from her prior service as U.S. Secretary of Energy and Governor of Michigan. As Secretary of Energy, s he led a workforce of approximately 110,000 employees and oversaw $200 billion of U.S. investments into companies and projects to accelerate the clean energy transition. She also brings a strong background in cybersecurity and protection of the power grid and electric utilities. Under her leadership, the Department of Energy invested heavily in cybersecurity tools and technologies to strengthen the resilience of U.S. energy infrastructure. In her two terms as Governor, Ms. Granholm spearheaded Michigan’s economic recovery after the Great Recession by diversifying the state’s economy to focus on clean energy and revitalizing the auto industry to build electric vehicles. Ms. Granholm also brings the perspective of a California resident and utility customer in light of California’s carbon neutrality goals and regulatory environment. | |||
Ms. Beliveau-Dunn has more than 30 years of experience as a technology executive and a transformational leader with experience in building and managing large scale infrastructure, cybersecurity, compute, cloud, networking, services and marketing operations, personnel management, and employee and leadership development. Her experience managing a large workforce, building network operations and security teams, and building infrastructure and efficiency through technology and process is valuable to the Board’s and Safety and Operations Committee’s oversight of cybersecurity issues facing the Company. She is also experienced in ESG matters, compensation, financial review, acquisitions, and risk and resiliency management. As a California resident, Ms. Beliveau-Dunn also provides the perspective of a utility customer impacted by California’s wildfires and regulatory environment. | |||
Mr. Morris has significant business and chief executive leadership experience in a highly regulated industry and provides expertise on insurance issues that impact the Company. He brings strategic planning, risk management, workforce management and financial analysis experience from 40 years of service at Pacific Life, which is particularly valuable to our Audit and Finance and Compensation and Executive Personnel Committees. Mr. Morris also provides the perspective of a Southern California resident impacted by California’s wildfires and regulatory environment, and an executive of a Fortune 500 business headquartered and doing business in the local markets served by SCE. | |||
Ms. Smith brings the perspective of a public company chief executive officer at Parsons, which was headquartered in Southern California until 2019 and continues to have key programs throughout the state. Her understanding of the impact of California’s regulatory landscape on SCE’s business customers contributes to the Board’s effective oversight of key issues confronting the electric utility industry. Ms. Smith brings strategic planning experience related to the acquisition and integration of technology businesses. Her operational experience in safety-intensive environments provides an important perspective to the Board and its Safety and Operations Committee. Ms. Smith also brings a strong background in cybersecurity through her aerospace and defense industry experience and is a certified cybersecurity governance professional by the National Association of Corporate Directors (“NACD”). She is certified as a cybersecurity governance professional. |
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Value and |
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Non-Qualified |
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Non-Equity |
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Deferred |
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Stock |
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Option |
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Incentive Plan |
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Compensation |
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All Other |
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Name and |
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Salary |
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Awards |
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Awards |
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Compensation |
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Earnings |
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Compensation |
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Total |
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Principal Position |
|
Year |
|
($) |
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($) |
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($) |
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($) |
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($) |
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($) |
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($) |
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Pedro J. Pizarro |
|
2024 |
|
1,400,000 |
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6,982,599 |
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2,327,506 |
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1,795,500 |
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1,225,053 |
|
78,913 |
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13,809,571 |
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EIX President and CEO |
|
2023 |
|
1,396,538 |
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6,825,189 |
|
2,275,001 |
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1,849,365 |
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2,505,218 |
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29,800 |
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14,881,111 |
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2022 |
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1,365,385 |
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6,576,144 |
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2,192,006 |
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1,960,470 |
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68,924 |
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28,300 |
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12,191,229 |
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Maria Rigatti |
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2024 |
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796,557 |
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1,650,138 |
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550,004 |
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742,900 |
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736,833 |
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20,700 |
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4,497,132 |
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EIX EVP and CFO |
|
2023 |
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765,962 |
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1,530,412 |
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510,137 |
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741,549 |
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1,129,358 |
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19,800 |
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4,697,218 |
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2022 |
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732,115 |
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1,433,324 |
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477,757 |
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761,570 |
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22,486 |
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18,300 |
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3,445,552 |
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Adam S. Umanoff |
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2024 |
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705,984 |
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1,171,547 |
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390,512 |
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716,656 |
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251,994 |
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20,700 |
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3,257,393 |
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EIX EVP, General Counsel and Corporate |
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2023 |
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670,962 |
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1,088,583 |
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362,815 |
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611,820 |
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308,548 |
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19,800 |
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3,062,528 |
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Secretary |
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2022 |
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635,962 |
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984,154 |
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328,006 |
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569,856 |
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320,176 |
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18,300 |
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2,856,454 |
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Steven D. Powell |
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2024 |
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763,689 |
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1,501,591 |
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500,510 |
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634,865 |
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478,489 |
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71,674 |
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3,950,818 |
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SCE President and CEO |
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2023 |
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707,500 |
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1,394,348 |
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464,761 |
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594,683 |
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819,612 |
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23,225 |
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4,004,129 |
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2022 |
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650,000 |
|
1,145,681 |
|
381,882 |
|
591,175 |
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8,501 |
|
22,480 |
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2,799,719 |
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Caroline Choi |
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2024 |
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540,484 |
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631,267 |
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210,368 |
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351,990 |
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243,000 |
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20,700 |
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1,997,809 |
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EIX and SCE EVP |
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2023 |
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519,623 |
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606,876 |
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202,286 |
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349,479 |
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337,216 |
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19,800 |
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2,035,280 |
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2022 |
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496,623 |
|
564,215 |
|
188,026 |
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334,835 |
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26,184 |
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18,300 |
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1,628,183 |
No Customers Found
Price
Yield
| Owner | Position | Direct Shares | Indirect Shares |
|---|---|---|---|
| PIZARRO PEDRO | - | 138,084 | 0 |
| Rigatti Maria C. | - | 57,322 | 0 |
| Taylor Peter J. | - | 32,372 | 0 |
| Choi Caroline | - | 26,918 | 0 |
| Choi Caroline | - | 20,881 | 0 |
| Murphy J Andrew | - | 19,850 | 0 |
| Trent Keith | - | 16,168 | 0 |
| Murphy J Andrew | - | 12,989 | 0 |
| Schilling Natalie K | - | 12,425 | 0 |
| Anderson Jill Charlotte | - | 10,861 | 320 |
| STUNTZ LINDA G | - | 7,186 | 1,131 |
| Anderson Jill Charlotte | - | 5,771 | 298 |
| Beliveau-Dunn Jeanne | - | 3,288 | 0 |
| Smith Carey A. | - | 2,907 | 0 |
| Bowman Erica S | - | 1,287 | 0 |
| Umanoff Adam S | - | 0 | 5,006 |
| Umanoff Adam S | - | 0 | 5,381 |