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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 March 31, 2011 |
||
or |
||
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 333-68630
EDISON MISSION ENERGY
(Exact name of registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization) |
95-4031807 (I.R.S. Employer Identification No.) |
|
3 MacArthur Place, Suite 100 Santa Ana, California (Address of principal executive offices) |
92707 (Zip Code) |
Registrant's telephone number, including area code: (714) 513-8000
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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES o NO o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer o | Non-accelerated filer ý (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
Number of shares outstanding of the registrant's Common Stock as of May 2, 2011: 100 shares (all shares held by an affiliate of the registrant).
i
ii
iii
iv
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
2010 Tax Relief Act | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 | |
AOI | adjusted operating income (loss) | |
BACT | best available control 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 | |
coal plants | Midwest Generation coal plants and Homer City electric generating station | |
Commonwealth Edison | Commonwealth Edison Company | |
CPS | Combined Pollutant Standard | |
EME | Edison Mission Energy | |
EMMT | Edison Mission Marketing & Trading, Inc. | |
GAAP | United States generally accepted accounting principles | |
GWh | gigawatt-hours | |
HAP(s) | hazardous air pollutant(s) | |
Homer City | EME Homer City Generation L.P. | |
LIBOR | London Interbank Offered Rate | |
MD&A | Management's Discussion and Analysis of Financial Condition and Results of Operations | |
Midwest Generation | Midwest Generation, LLC | |
MMBtu | million British thermal units | |
Moody's | Moody's Investors Service, Inc. | |
MW | megawatts | |
MWh | megawatt-hours | |
NOX | nitrogen oxide | |
NYISO | New York Independent System Operator | |
PJM | PJM Interconnection, LLC | |
PRB | Powder River Basin | |
PSD | Prevention of Significant Deterioration | |
RPM | Reliability Pricing Model | |
S&P | Standard & Poor's Ratings Services | |
SO2 | sulfur dioxide | |
US EPA | United States Environmental Protection Agency | |
U.S. Treasury grants | Cash grants, under the American Recovery and Reinvestment Act of 2009 | |
v
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, unaudited) |
|||||||||
---|---|---|---|---|---|---|---|---|---|
|
Three Months Ended March 31, |
||||||||
|
2011 |
2010 |
|||||||
Operating Revenues |
$ | 550 | $ | 651 | |||||
Operating Expenses |
|||||||||
Fuel |
182 | 213 | |||||||
Plant operations |
192 | 158 | |||||||
Plant operating leases |
44 | 44 | |||||||
Depreciation and amortization |
72 | 59 | |||||||
Administrative and general |
43 | 47 | |||||||
Total operating expenses |
533 | 521 | |||||||
Operating income |
17 |
130 |
|||||||
Other Income (Expense) |
|||||||||
Equity in income (loss) from unconsolidated affiliates |
(5 | ) | 17 | ||||||
Dividend income |
1 | 16 | |||||||
Interest income |
1 | 1 | |||||||
Interest expense, net of capitalized interest |
(80 | ) | (68 | ) | |||||
Other income (expense), net |
3 | 2 | |||||||
Total other income (expense) |
(80 |
) |
(32 |
) |
|||||
Income (loss) from continuing operations before income taxes |
(63 |
) |
98 |
||||||
Provision (benefit) for income taxes |
(45 | ) | 23 | ||||||
Income (Loss) from Continuing Operations |
(18 |
) |
75 |
||||||
Income (Loss) from Operations of Discontinued Subsidiaries, net of tax (Note 13) |
(2 | ) | 6 | ||||||
Net Income (Loss) |
(20 |
) |
81 |
||||||
Net (Income) Loss Attributable to Noncontrolling Interests |
|
|
|||||||
Net Income (Loss) Attributable to Edison Mission Energy Common Shareholder |
$ |
(20 |
) |
$ |
81 |
||||
Amounts Attributable to Edison Mission Energy Common Shareholder |
|||||||||
Income (loss) from continuing operations, net of tax |
$ | (18 | ) | $ | 75 | ||||
Income (loss) from discontinued operations, net of tax |
(2 | ) | 6 | ||||||
Net Income (Loss) Attributable to Edison Mission Energy Common Shareholder |
$ |
(20 |
) |
$ |
81 |
||||
The accompanying notes are an integral part of these consolidated financial statements.
1
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in millions, unaudited) |
|||||||||
---|---|---|---|---|---|---|---|---|---|
|
Three Months Ended March 31, |
||||||||
|
2011 |
2010 |
|||||||
Net Income (Loss) |
$ | (20 | ) | $ | 81 | ||||
Other comprehensive income (loss), net of tax |
|||||||||
Pension and postretirement benefits other than pensions |
|||||||||
Amortization of net loss included in expenses, net of tax |
1 | | |||||||
Unrealized gains (losses) on derivatives qualified as cash flow hedges |
|||||||||
Unrealized holding gains arising during period, net of income tax expense of $4 and $62 for the three months ended March 31, 2011 and 2010, respectively |
6 | 95 | |||||||
Reclassification adjustments included in net income (loss), net of income tax benefit of $6 and $14 for the three months ended March 31, 2011 and 2010, respectively |
(10 | ) | (20 | ) | |||||
Other comprehensive income (loss) |
(3 |
) |
75 |
||||||
Comprehensive Income (Loss) |
(23 |
) |
156 |
||||||
Comprehensive (Income) Loss Attributable to Noncontrolling Interests |
|
|
|||||||
Comprehensive Income (Loss) Attributable to Edison Mission Energy Common Shareholder |
$ |
(23 |
) |
$ |
156 |
||||
The accompanying notes are an integral part of these consolidated financial statements.
2
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (in millions, unaudited) |
|||||||||
---|---|---|---|---|---|---|---|---|---|
|
March 31, 2011 |
December 31, 2010 |
|||||||
Assets |
|||||||||
Current Assets |
|||||||||
Cash and cash equivalents |
$ | 1,183 | $ | 1,075 | |||||
Accounts receivabletrade |
106 | 170 | |||||||
Receivables from affiliates |
236 | 192 | |||||||
Inventory |
258 | 236 | |||||||
Derivative assets |
38 | 46 | |||||||
Restricted cash |
10 | 2 | |||||||
Margin and collateral deposits |
46 | 59 | |||||||
Prepaid expenses and other |
75 | 79 | |||||||
Total current assets |
1,952 |
1,859 |
|||||||
Investments in Unconsolidated Affiliates |
542 |
557 |
|||||||
Property, Plant and Equipment, less accumulated depreciation of $1,833 and $1,759 at respective dates |
5,360 |
5,332 |
|||||||
Other Assets |
|||||||||
Deferred financing costs |
54 | 54 | |||||||
Long-term derivative assets |
66 | 70 | |||||||
Restricted deposits |
38 | 44 | |||||||
Rent payments in excess of levelized rent expense under plant operating leases |
1,219 | 1,187 | |||||||
Other long-term assets |
226 | 218 | |||||||
Total other assets |
1,603 |
1,573 |
|||||||
Total Assets |
$ |
9,457 |
$ |
9,321 |
|||||
The accompanying notes are an integral part of these consolidated financial statements.
3
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (in millions, except share and per share amounts, unaudited) |
|||||||||
---|---|---|---|---|---|---|---|---|---|
|
March 31, 2011 |
December 31, 2010 |
|||||||
Liabilities and Shareholder's Equity |
|||||||||
Current Liabilities |
|||||||||
Accounts payable |
$ | 105 | $ | 90 | |||||
Payables to affiliates |
17 | 18 | |||||||
Accrued liabilities |
139 | 201 | |||||||
Derivative liabilities |
7 | 6 | |||||||
Interest payable |
103 | 31 | |||||||
Deferred taxes |
33 | 34 | |||||||
Current maturities of long-term debt |
53 | 48 | |||||||
Short-term debt |
53 | 96 | |||||||
Total current liabilities |
510 | 524 | |||||||
Long-term debt net of current maturities |
4,492 |
4,342 |
|||||||
Deferred taxes and tax credits |
820 | 836 | |||||||
Deferred revenues |
159 | 160 | |||||||
Long-term derivative liabilities |
15 | 19 | |||||||
Other long-term liabilities |
663 | 619 | |||||||
Total Liabilities |
6,659 |
6,500 |
|||||||
Commitments and Contingencies (Notes 5, 6, 9 and 10) |
|||||||||
Equity |
|||||||||
Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of March 31, 2011 and December 31, 2010 |
64 | 64 | |||||||
Additional paid-in capital |
1,338 | 1,336 | |||||||
Retained earnings |
1,426 | 1,448 | |||||||
Accumulated other comprehensive loss |
(34 | ) | (31 | ) | |||||
Total Edison Mission Energy common shareholder's equity |
2,794 |
2,817 |
|||||||
Noncontrolling Interests |
4 |
4 |
|||||||
Total Equity |
2,798 |
2,821 |
|||||||
Total Liabilities and Equity |
$ |
9,457 |
$ |
9,321 |
|||||
The accompanying notes are an integral part of these consolidated financial statements.
4
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions, unaudited) |
|||||||||
---|---|---|---|---|---|---|---|---|---|
|
Three Months Ended March 31, | ||||||||
|
2011 |
2010 |
|||||||
Cash Flows From Operating Activities |
|||||||||
Net income (loss) |
$ | (20 | ) | $ | 81 | ||||
(Income) loss from discontinued operations |
2 | (6 | ) | ||||||
Income (loss) from continuing operations, net |
(18 | ) | 75 | ||||||
Adjustments to reconcile income (loss) to net cash provided by operating activities: |
|||||||||
Equity in (income) loss from unconsolidated affiliates |
5 | (17 | ) | ||||||
Distributions from unconsolidated affiliates |
5 | 21 | |||||||
Depreciation and amortization |
81 | 63 | |||||||
Deferred taxes and tax credits |
(15 | ) | 29 | ||||||
Changes in operating assets and liabilities: |
|||||||||
Decrease (increase) in margin and collateral deposits |
13 | (4 | ) | ||||||
Decrease in accounts receivables |
20 | 76 | |||||||
Increase in inventory |
(22 | ) | (2 | ) | |||||
(Increase) decrease in prepaid expenses and other |
(2 | ) | 1 | ||||||
Decrease in restricted cash |
| 3 | |||||||
Increase in rent payments in excess of levelized rent expense |
(32 | ) | (45 | ) | |||||
Decrease in accounts payable and other current liabilities |
(13 | ) | (84 | ) | |||||
Increase in interest payable |
72 | 71 | |||||||
Decrease in derivative assets and liabilities |
4 | 118 | |||||||
Decrease in other operatingassets |
| 5 | |||||||
Increase in other operatingliabilities |
16 | 2 | |||||||
Operating cash flow from continuing operations |
114 | 312 | |||||||
Operating cash flow from discontinued operations |
(2 | ) | 6 | ||||||
Net cash provided by operating activities |
112 | 318 | |||||||
Cash Flows From Financing Activities |
|||||||||
Borrowings on long-term debt |
88 | 47 | |||||||
Payments on long-term debt agreements |
(8 | ) | (3 | ) | |||||
Borrowings on short-term debt |
32 | | |||||||
Payments to affiliates related to stock-based awards |
(2 | ) | (1 | ) | |||||
Financing costs |
(6 | ) | (9 | ) | |||||
Net cash provided by financing activities from continuing operations |
104 | 34 | |||||||
Cash Flows From Investing Activities |
|||||||||
Capital expenditures |
(111 | ) | (83 | ) | |||||
Proceeds from return of capital and loan repayments and sale of assets |
9 | 16 | |||||||
Investments in and loans to unconsolidated affiliates |
(4 | ) | | ||||||
Maturities of short-term investments |
| 1 | |||||||
Increase in restricted deposits |
(1 | ) | | ||||||
Investments in other assets |
(1 | ) | (49 | ) | |||||
Net cash used in investing activities from continuing operations |
(108 | ) | (115 | ) | |||||
Effect of consolidation of variable interest entity on cash |
| 5 | |||||||
Effect on cash from deconsolidation of variable interest entities |
| (4 | ) | ||||||
Net increase in cash and cash equivalents |
108 | 238 | |||||||
Cash and cash equivalents at beginning of period |
1,075 | 796 | |||||||
Cash and cash equivalents at end of period |
$ | 1,183 | $ | 1,034 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
5
EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2011
(Unaudited)
Note 1. Summary of Significant Accounting Policies
Edison Mission Energy's (EME's) significant accounting policies were described in "Note 1Summary of Significant Accounting Policies" on page 94 of EME's annual report on Form 10-K for the year ended December 31, 2010. EME follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2011 as discussed below in "New Accounting Guidance." This quarterly report should be read in conjunction with such financial statements.
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position and results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three months ended March 31, 2011 are not necessarily indicative of the operating results for the full year. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.
Certain prior year reclassifications have been made to conform to the current year financial statement presentation pertaining to immaterial items.
The December 31, 2010 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.
Cash equivalents included money market funds totaling $967 million and $813 million at March 31, 2011 and December 31, 2010, respectively. The carrying value of cash equivalents equals the fair value as all investments have maturities of less than three months.
Inventory is stated at the lower of weighted average cost or market. Inventory consisted of the following:
(in millions) |
March 31, 2011 |
December 31, 2010 |
|||||
---|---|---|---|---|---|---|---|
Coal, fuel oil and other raw materials |
$ | 184 | $ | 163 | |||
Spare parts, materials and supplies |
74 | 73 | |||||
Total inventory |
$ | 258 | $ | 236 | |||
6
Accounting Guidance Adopted in 2011
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. EME adopted this guidance effective January 1, 2011. The adoption of this accounting standards update did not have a material impact on EME'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. EME adopted this guidance effective January 1, 2011.
Note 2. Consolidated Statement of Changes in Equity
The following table provides the changes in equity for the three months ended March 31, 2011:
|
|
EME Shareholder's Equity | |
||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Total Equity |
Common Stock |
Additional Paid-in Capital |
Retained Earnings |
Accumulated Other Comprehensive Income (Loss) |
Non- controlling Interest |
|||||||||||||
Balance at December 31, 2010 |
$ | 2,821 | $ | 64 | $ | 1,336 | $ | 1,448 | $ | (31 | ) | $ | 4 | ||||||
Net loss |
(20 | ) | | | (20 | ) | | | |||||||||||
Other comprehensive loss |
(3 | ) | | | | (3 | ) | | |||||||||||
Payments to Edison |
(2 | ) | | | (2 | ) | | | |||||||||||
Other stock transactions, net |
2 | | 2 | | | | |||||||||||||
Balance at March 31, 2011 |
$ | 2,798 | $ | 64 | $ | 1,338 | $ | 1,426 | $ | (34 | ) | $ | 4 | ||||||
7
The following table provides the changes in equity for the three months ended March 31, 2010:
|
|
EME Shareholder's Equity | |
||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Total Equity |
Common Stock |
Additional Paid-in Capital |
Retained Earnings |
Accumulated Other Comprehensive Income (Loss) |
Non- controlling Interest |
|||||||||||||
Balance at December 31, 2009 |
$ | 2,837 | $ | 64 | $ | 1,339 | $ | 1,280 | $ | 78 | $ | 76 | |||||||
Impact of deconsolidation of |
(71 | ) | | | | | (71 | ) | |||||||||||
Cumulative effect of a change |
10 | | | 10 | | | |||||||||||||
Net income |
81 | | | 81 | | | |||||||||||||
Other comprehensive income |
75 | | | | 75 | | |||||||||||||
Payments to Edison |
(1 | ) | | | (1 | ) | | | |||||||||||
Other stock transactions, net |
1 | | 1 | | | | |||||||||||||
Balance at March 31, 2010 |
$ | 2,932 | $ | 64 | $ | 1,340 | $ | 1,370 | $ | 153 | $ | 5 | |||||||
- 1
- For the quarter ended March 31, 2010, reflects the impact of adopting accounting guidance related to variable interest entities.
Note 3. Variable Interest Entities
Projects or Entities that are Consolidated
At March 31, 2011 and December 31, 2010, EME consolidated 13 wind projects with a total generating capacity of 500 MW that have minority interests held by others. EME also had a 50% partnership interest in the American Bituminous Power Partners, L.P. project, commonly referred to as the Ambit project. In determining that EME was the primary beneficiary, the key factors considered were EME's ability to direct commercial and operating activities and EME's obligation to absorb losses and right to receive benefits that could potentially be significant to the variable interest entities. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
8
The following table presents summarized financial information of the projects that were consolidated by EME:
(in millions) |
March 31, 2011 |
December 31, 2010 |
||||||
---|---|---|---|---|---|---|---|---|
Current assets |
$ | 36 | $ | 26 | ||||
Net property, plant and equipment |
726 | 739 | ||||||
Other long-term assets |
5 | 6 | ||||||
Total assets |
$ | 767 | $ | 771 | ||||
Current liabilities |
$ | 23 | $ | 25 | ||||
Long-term debt net of current maturities |
70 | 71 | ||||||
Deferred revenues |
72 | 71 | ||||||
Other long-term liabilities |
21 | 21 | ||||||
Total liabilities |
$ | 186 | $ | 188 | ||||
Noncontrolling interests |
$ | 4 | $ | 4 | ||||
Assets serving as collateral for the debt obligations had a carrying value of $167 million and $163 million at March 31, 2011 and December 31, 2010, respectively, and primarily consist of property, plant and equipment.
Projects that are not Consolidated
EME accounts for domestic energy projects in which it has a 50% or less ownership interest, and cannot exercise unilateral control, under the equity method. At March 31, 2011 and December 31, 2010, EME 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 EME operates three of the four Big 4 projects and EME's partner provides the fuel management services. In addition, the executive director of these projects is provided by EME's partner. Commercial and operating activities are jointly controlled by a management committee of each variable interest entity. Accordingly, EME continues to account for its variable interests under the equity method.
At March 31, 2011 and December 31, 2010, EME accounts for its interests in two renewable wind generating facilities, the Elkhorn Ridge and San Juan Mesa projects, under the equity method. The commercial and operating activities of these entities are directed by a management committee composed of representatives of each partner. Thus, EME is not the primary beneficiary of these projects. In addition, EME accounts for its interests in a wind project under construction, Community Wind North, under the equity method.
The following table presents the carrying amount of EME's investments in unconsolidated variable interest entities and the maximum exposure to loss for each investment:
|
March 31, 2011 | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
Investment |
Maximum Exposure |
|||||
Natural gas-fired projects |
$ | 315 | $ | 315 | |||
Renewable energy projects |
227 | 227 | |||||
9
EME's maximum exposure to loss in its variable interest entities accounted for under the equity method is generally limited to its investment in these entities. Two of EME's domestic energy projects have long-term debt that is secured by a pledge of assets of the project entity, but does not provide for recourse to EME. Accordingly, a default under such project financings could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's investment, but would not require EME to contribute additional capital. At March 31, 2011, entities which EME has accounted for under the equity method had indebtedness of $115 million, of which $41 million is proportionate to EME's ownership interest in these two projects.
Note 4. 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 a liability should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk. The fair value of derivative assets' nonperformance risk was not material as of March 31, 2011 and December 31, 2010.
EME 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).
10
The following table sets forth EME's assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:
|
March 31, 2011 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Level 1 |
Level 2 |
Level 3 |
Netting and Collateral1 |
Total |
|||||||||||||
Assets at Fair Value |
||||||||||||||||||
Money market funds2 |
$ | 967 | $ | | $ | | $ | | $ | 967 | ||||||||
Derivative contracts |
||||||||||||||||||
Electricity |
$ | | $ | 67 | $ | 91 | $ | (54 | ) | $ | 104 | |||||||
Fuel oil |
7 | | | (7 | ) | | ||||||||||||
Total commodity contracts |
7 | 67 | 91 | (61 | ) | 104 | ||||||||||||
Total assets |
$ | 974 | $ | 67 | $ | 91 | $ | (61 | ) | $ | 1,071 | |||||||
Liabilities at Fair Value |
||||||||||||||||||
Derivative contracts |
||||||||||||||||||
Electricity |
$ | | $ | 13 | $ | 8 | $ | (14 | ) | $ | 7 | |||||||
Natural gas |
| 1 | | | 1 | |||||||||||||
Total commodity contracts |
| 14 | 8 | (14 | ) | 8 | ||||||||||||
Interest rate contracts |
| 14 | | | 14 | |||||||||||||
Total liabilities |
$ | | $ | 28 | $ | 8 | $ | (14 | ) | $ | 22 | |||||||
December 31, 2010 |
||||||||||||||||||
Assets at Fair Value |
||||||||||||||||||
Money market funds2 |
$ | 813 | $ | | $ | | $ | | $ | 813 | ||||||||
Derivative contracts |
||||||||||||||||||
Electricity |
$ | | $ | 70 | $ | 107 | $ | (61 | ) | $ | 116 | |||||||
Natural gas |
1 | | | (1 | ) | | ||||||||||||
Fuel oil |
8 | | | (8 | ) | | ||||||||||||
Total commodity contracts |
9 | 70 | 107 | (70 | ) | 116 | ||||||||||||
Total assets |
$ | 822 | $ | 70 | $ | 107 | $ | (70 | ) | $ | 929 | |||||||
Liabilities at Fair Value |
||||||||||||||||||
Derivative contracts |
||||||||||||||||||
Electricity |
$ | | $ | 12 | $ | 16 | $ | (21 | ) | $ | 7 | |||||||
Natural gas |
| 2 | | | 2 | |||||||||||||
Coal |
| 1 | | (1 | ) | | ||||||||||||
Total commodity contracts |
| 15 | 16 | (22 | ) | 9 | ||||||||||||
Interest rate contracts |
| 16 | | | 16 | |||||||||||||
Total liabilities |
$ | | $ | 31 | $ | 16 | $ | (22 | ) | $ | 25 | |||||||
- 1
- Represents
cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions
classified within the same level is included in that level.
- 2
- Money market funds are included in cash and cash equivalents on EME's consolidated balance sheets.
11
The following table sets forth a summary of changes in the fair value of assets and liabilities, net categorized as Level 3:
|
Three Months Ended March 31, |
|||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
||||||
Fair value, net assets at beginning of period |
$ | 91 | $ | 173 | ||||
Total realized/unrealized gains (losses) |
||||||||
Included in earnings1 |
| 45 | ||||||
Included in accumulated other comprehensive income (loss) |
1 | 6 | ||||||
Purchases |
5 | 4 | ||||||
Settlements |
(12 | ) | (28 | ) | ||||
Transfers in or out of Level 3 |
(2 | ) | (1 | ) | ||||
Fair value, net assets at end of period |
$ | 83 | $ | 199 | ||||
Change during the period in unrealized gains (losses) related to |
$ | (6 | ) | $ | 46 | |||
- 1
- Reported in operating revenues on EME's consolidated statements of operations.
EME determines the fair value of transfers in and transfers out of each level at the end of each reporting period. There were no significant transfers between levels during the first quarters of 2011 and 2010.
Valuation Techniques used to Determine Fair Value
Level 1 includes assets and liabilities where unadjusted quoted prices in active markets are available at the measurement date for identical assets and liabilities. Financial assets and liabilities classified as Level 1 include exchange-traded derivatives 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 over-the-counter derivatives.
Derivative contracts that are over-the-counter traded are valued using pricing models 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. Forward market prices are developed based on the source that best represents trade activity in each market. 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.
12
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, qualifying facilities contracts, derivative contracts that trade infrequently (such as congestion revenue rights in the California market, financial transmission rights traded in markets outside California and over-the-counter derivatives at illiquid locations), long-term power agreements, and derivative contracts with counterparties that have significant nonperformance risks are classified as Level 3. In circumstances where EME 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, EME continues to assess valuation methodologies used to determine fair value.
For derivative contracts that trade infrequently (illiquid financial transmission rights and congestion revenue rights), changes in fair value are based on the hypothetical sale of illiquid positions. Objective criteria are reviewed, including system congestion and other underlying drivers and fair value is adjusted when it is concluded that a change in objective criteria would result in a new valuation that better reflects fair value. For illiquid long-term power agreements, fair value is based upon a 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 EME's derivatives that are classified as Level 3 is determined using uncorroborated non-binding broker quotes and models that may require EME 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.
The carrying amounts and fair values of EME's long-term debt were as follows:
|
March 31, 2011 | December 31, 2010 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
|||||||||
Long-term debt, including current portion |
$ | 4,544 | $ | 3,843 | $ | 4,390 | $ | 3,670 | |||||
In assessing the fair value of EME's long-term debt, EME primarily uses quoted market prices, except for floating-rate debt for which the carrying amounts were considered a reasonable estimate of fair value.
The carrying amount of trade receivables, payables and short-term debt approximates fair value.
Note 5. Debt and Credit Agreements
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 $255.2 million, which included a
13
$227 million ten-year term loan (expiring in December 2020), a $23 million seven-year letter of credit facility and a $5.2 million seven-year working capital facility. At March 31, 2011, $227 million was outstanding under this loan. The amount of outstanding letters of credit was $13 million. Interest under the term loan accrues at London Interbank Offered Rate (LIBOR) plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary. Viento Funding II, Inc. entered into interest rate swap agreements at 3.415% to hedge the majority of the variable interest rate under the term loan. Two-thirds of the notional amount as of December 31, 2010 (approximately $92 million) under the swap agreements entered in connection with the 2009 financing were left unchanged at 3.175%. For further details regarding the interest rate swap agreements, see Note 6Derivative Instruments and Hedging Activities. In conjunction with the foregoing, EME wrote off $3 million of deferring financing costs and incurred a loss of $2 million from termination of interest rate swaps, included as part of interest expense on the consolidated statement of operations.
Other Letters of Credit Facilities
As of March 31, 2011, a subsidiary of EME had a $10 million letter of credit facility with $2 million outstanding letters of credit.
At March 31, 2011, standby letters of credit under EME's credit facility aggregated $80 million and were scheduled to expire as follows: $53 million in 2011 and $27 million in 2012. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $41 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 $8 million in 2018. Certain letters of credit are subject to automatic annual renewal provisions.
Note 6. Derivative Instruments and Hedging Activities
EME uses derivative instruments to reduce EME's exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EME'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 EME 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 EME'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 EME'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.
14
Where EME's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EME presents its derivative assets and liabilities on a net basis on its consolidated balance sheets.
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging and trading activities:
March 31, 2011 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
Hedging Activities | |
|||||||||||
Commodity |
Instrument |
Classification |
Unit of Measure |
Cash Flow Hedges |
Economic Hedges |
Trading Activities |
||||||||||
Electricity |
Forwards/Futures | Sales | GWh | 16,899 | 1 | 20,400 | 3 | 33,336 | ||||||||
Electricity |
Forwards/Futures | Purchases | GWh | 306 | 1 | 21,079 | 3 | 35,455 | ||||||||
Electricity |
Capacity | Sales | MW-Day (in thousands) |
186 | 2 | | 123 | 2 | ||||||||
Electricity |
Capacity | Purchases | MW-Day (in thousands) |
21 | 2 | | 379 | 2 | ||||||||
Electricity |
Congestion | Sales | GWh | | 136 | 4 | 9,244 | 4 | ||||||||
Electricity |
Congestion | Purchases | GWh | | 863 | 4 | 146,786 | 4 | ||||||||
Natural gas |
Forwards/Futures | Sales | bcf | | | 27.4 | ||||||||||
Natural gas |
Forwards/Futures | Purchases | bcf | | | 28.6 | ||||||||||
Fuel oil |
Forwards/Futures | Sales | barrels | | | 35,000 | ||||||||||
Fuel oil |
Forwards/Futures | Purchases | barrels | | 240,000 | 35,000 | ||||||||||
Coal |
Forwards/Futures | Sales | tons | | | 2,731,000 | ||||||||||
Coal |
Forwards/Futures | Purchases | tons | | | 2,638,000 | ||||||||||
(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 | $ | 92 | June 2016 | ||||
Amortizing interest rate swap |
Convert floating rate (6-month LIBOR) debt to fixed rate (3.415%) debt |
Cash flow |
113 |
December 2020 |
|||||
Amortizing 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 |
|||||
15
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 |
|||||
- 1
- EME's
hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the
coal plants which meet the normal purchases and sales exception and are accounted for on the accrual method.
- 2
- EME's
hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Reliability Pricing Model (RPM) auction is not
accounted for as a derivative.
- 3
- EME
also entered into transactions that adjust financial and physical positions, or day-ahead and real-time positions to
reduce costs or increase gross margin. These positions largely offset each other. The net sales positions of these categories are primarily related to hedge transactions that are not designated as
cash flow hedges.
- 4
- Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.
16
Fair Value of Derivative Instruments
The following table summarizes the fair value of derivative instruments reflected on EME's consolidated balance sheets:
March 31, 2011 | |||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Derivative Assets | Derivative Liabilities | |
||||||||||||||||||||
(in millions) |
Short-term |
Long-term |
Subtotal |
Short-term |
Long-term |
Subtotal |
Net Assets |
||||||||||||||||
Non-trading activities |
|||||||||||||||||||||||
Cash flow hedges |
$ | 44 | $ | 6 | $ | 50 | $ | 9 | $ | 23 | $ | 32 | $ | 18 | |||||||||
Economic hedges |
59 | 6 | 65 | 56 | 1 | 57 | 8 | ||||||||||||||||
Trading activities |
139 | 96 | 235 | 106 | 26 | 132 | 103 | ||||||||||||||||
|
242 | 108 | 350 | 171 | 50 | 221 | 129 | ||||||||||||||||
Netting and |
(204 | ) | (42 | ) | (246 | ) | (164 | ) | (35 | ) | (199 | ) | (47 | ) | |||||||||
Total |
$ | 38 | $ | 66 | $ | 104 | $ | 7 | $ | 15 | $ | 22 | $ | 82 | |||||||||
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 |
(269 | ) | (37 | ) | (306 | ) | (223 | ) | (35 | ) | (258 | ) | (48 | ) | |||||||||
Total |
$ | 46 | $ | 70 | $ | 116 | $ | 6 | $ | 19 | $ | 25 | $ | 91 | |||||||||
- 1
- Netting of derivative receivables and derivative payables and the related cash collateral received and paid is permitted when a legally enforceable master netting agreement exists with a derivative counterparty.
17
Income Statement Impact of Derivative Instruments
The following table provides the activity of accumulated other comprehensive income, containing information about the changes in the fair value of cash flow hedges, to the extent effective, and reclassification from accumulated other comprehensive income into results of operations:
|
Cash Flow Hedge Activity1 Three Months Ended March 31, |
|
||||||
---|---|---|---|---|---|---|---|---|
|
Income Statement Location |
|||||||
(in millions) |
2011 |
2010 |
||||||
Accumulated other comprehensive income derivative gain at January 1 |
$ | 27 | $ | 175 | ||||
Effective portion of changes in fair value |
10 | 157 | ||||||
Reclassification from accumulated other comprehensive income to net income |
(16 | ) | (34 | ) | Operating revenues | |||
Accumulated other comprehensive income derivative gain at March 31 |
$ | 21 | $ | 298 | ||||
- 1
- Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at March 31, 2011 and 2010 were $12 million and $180 million, respectively.
For additional information related to accumulated other comprehensive income, see Note 11Accumulated Other Comprehensive Income (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. EME recorded net gains of $2 million and $9 million during the first quarters of 2011 and 2010, respectively, in operating revenues on the consolidated statements of operations representing the amount of cash flow hedge ineffectiveness.
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 March 31, |
|||||||
---|---|---|---|---|---|---|---|---|---|
|
Income Statement Location |
||||||||
(in millions) |
2011 |
2010 |
|||||||
Economic hedges |
Operating revenues | $ | 6 | $ | (4 | ) | |||
|
Fuel costs | 6 | 1 | ||||||
Trading activities |
Operating revenues |
16 |
47 |
||||||
Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has 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 March 31, 2011 and, accordingly, the contingent features described below do not currently have liquidity exposure. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their respective credit facilities. The credit facilities each
18
contain financial covenants. 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 EME 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 EME, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.
Margin and Collateral Deposits
Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions. EME nets counterparty receivables and payables where balances exist under master netting arrangements. EME presents the portion of its margin and cash 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) |
March 31, 2011 |
December 31, 2010 |
||||||
---|---|---|---|---|---|---|---|---|
Collateral provided to counterparties |
||||||||
Offset against derivative liabilities |
$ | 1 | $ | 4 | ||||
Reflected in margin and collateral deposits |
46 | 59 | ||||||
Collateral received from counterparties |
||||||||
Offset against derivative assets |
48 | 52 | ||||||
19
The table below provides a reconciliation of income tax expense (benefit) computed at the federal statutory income tax rate to the income tax provision (benefit):
|
Three Months Ended March 31, |
|||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
||||||
Income (loss) from continuing operations before income taxes |
$ | (63 | ) | $ | 98 | |||
Provision (benefit) for income taxes at federal statutory rate of 35% |
$ | (23 | ) | $ | 34 | |||
Increase (decrease) in income tax from: |
||||||||
State tax-net of federal provision (benefit) (excludes state tax settlement) |
(5 | ) | 4 | |||||
Production tax credits, net |
(18 | ) | (14 | ) | ||||
Qualified production deduction |
(1 | ) | 1 | |||||
Other |
2 | (2 | ) | |||||
Total provision (benefit) for income taxes from continuing operations |
$ | (45 | ) | $ | 23 | |||
Effective tax rate |
72% | 23% | ||||||
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 on audit. 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.
There was no change in unrecognized tax benefits from December 31, 2010. As of March 31, 2011 and December 31, 2010, if recognized, $148 million of the unrecognized tax benefits 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 remain subject to audit. The Internal Revenue Service examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included proposed adjustments for one item related to EME. The EME-related proposed adjustment increases the taxable gain on the 2004 sale of EME's international assets, which if sustained, would result in a federal tax payment of approximately $187 million, including interest and penalties (the Internal Revenue Service has asserted a 40% penalty for understatement of tax liability related to this matter). Edison International disagrees with the proposed adjustments and filed a protest with the Internal Revenue Service in the first quarter of 2011.
20
Accrued Interest and Penalties
The total amount of accrued interest and penalties related to EME's income tax liabilities was $34 million and $32 million as of March 31, 2011 and December 31, 2010, respectively.
The net after-tax interest and penalties recognized in income tax expense was $1 million and $3 million for the three months ended March 31, 2011 and 2010, respectively.
Note 8. Compensation and Benefit Plans
Pension Plans and Postretirement Benefits Other Than Pensions
Contributions to EME's pension plans were $3 million during the quarter ended March 31, 2011, and EME estimates $17 million in contributions for the remainder of 2011.
The following were components of pension expense:
|
Three Months Ended March 31, |
||||||
---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
|||||
Service cost |
$ | 4 | $ | 4 | |||
Interest cost |
4 | 3 | |||||
Expected return on plan assets |
(3 | ) | (2 | ) | |||
Amortization of net loss |
1 | 1 | |||||
Total expense |
$ | 6 | $ | 6 | |||
Postretirement Benefits Other Than Pensions
Contributions to EME's postretirement benefits other than pensions were $1 million during the quarter ended March 31, 2011, and EME estimates $1 million in contributions for the remainder of 2011.
The following were components of postretirement benefits expense:
|
Three Months Ended March 31, |
||||||
---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
|||||
Service cost |
$ | 1 | $ | 1 | |||
Interest cost |
2 | 1 | |||||
Total expense |
$ | 3 | $ | 2 | |||
21
Note 9. Commitments and Contingencies
At March 31, 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 $677 million, summarized as follows: $373 million for the remainder of 2011, $255 million in 2012 and $49 million in 2013.
At March 31, 2011, EME had commitments to purchase wind turbines of $90 million due in 2011. EME's failure to schedule turbine delivery by June 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $21 million charge against earnings. EME 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 EME 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, EME 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. In April 2011, the 55 MW Pinnacle wind project in West Virginia, which will deploy the 23 wind turbines purchased from Mitsubishi, commenced construction.
At March 31, 2011, EME's subsidiaries had firm commitments to spend approximately $153 million during the remainder of 2011 on capital and construction expenditures. These expenditures primarily relate to selective non-catalytic reduction (SNCR) equipment at the Midwest Generation plants, the construction of wind projects and non-environmental improvements at the coal plants. EME intends to fund these expenditures through project level and turbine vendor financing, U.S. Treasury grants, cash on hand and cash generated from operations.
EME and certain of its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts included performance guarantees and indemnifications.
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 claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification
22
claim. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. 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. Due to the nature of the obligations under these indemnities, a maximum potential liability cannot be determined. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the litigation discussed below under "ContingenciesMidwest Generation New Source Review Lawsuit." 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 its 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. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. 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 228 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at March 31, 2011. Midwest Generation had recorded a liability of $56 million at March 31, 2011 related to this contract 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. Payments would be triggered under this indemnity by a valid claim from the sellers. 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. For discussion of the New Source Review lawsuit filed against Homer City, see "ContingenciesHomer City New Source Review Lawsuit." EME has not recorded a liability related to this indemnity.
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. Payments would be triggered under these indemnities by
23
valid claims from the sellers or purchasers, as the case may be. At March 31, 2011, EME had recorded a liability of $44 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). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined.
Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. No significant amounts are recorded as a liability for these matters.
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. No significant amounts are recorded as a liability for these matters.
Legislative and regulatory activities by federal, state and local authorities in the United States relating to energy and the environment impose numerous restrictions and requirements with respect to the operation of EME subsidiaries' existing facilities and affect the timing, cost, location, design, construction, and operation of new facilities by EME's subsidiaries, as well as the cost of mitigating the environmental impacts of past operations.
With respect to potential liabilities arising under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation had accrued approximately $7 million at March 31, 2011 for estimated environmental investigation and remediation costs for the Midwest Generation plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for investigation and/or remediation where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that require remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified.
24
Midwest Generation New Source Review Lawsuit
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 against Midwest Generation, but not Commonwealth Edison, 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) emissions 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 emissions 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.
In March 2010, nine of the ten counts related to PSD requirements in the complaint were dismissed, and the tenth count was also dismissed to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. Following those dismissals, the government plaintiffs filed an amended complaint, with claims that attempted to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. In March 2011, the court again dismissed the nine PSD claims previously dismissed in 2010, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court 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.
An adverse decision could involve penalties and remedial actions that could have a material adverse 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 Lawsuit
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 and its implementing regulations, including requirements contained in the Pennsylvania State Implementation Plan, 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
25
sufficient to meet BACT emissions 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. 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, compensatory and punitive damages.
In April 2011, Homer City filed motions to dismiss both complaints. An adverse decision could involve penalties, remedial actions and damages that could have a material adverse 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.
Note 10. Environmental Developments
In March 2011, the US EPA issued draft "National Emission Standards for Hazardous Air Pollutants," limiting emissions of hazardous air pollutants (HAPs) from coal- and oil-fired electrical generating units. The regulations are expected to be finalized by November 2011. Based on its continuing review, EME does not expect these standards, 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 Powder River Basin (PRB) coal, to meet emissions limits for criteria pollutants, such as nitrogen oxide (NOx) and sulfur dioxide (SO2) as well as for HAPs, such as mercury, acid gas and non-mercury metals. With respect to the Homer City plant, the proposed standards, like the pending Clear Air Transport Rule, will require additional reductions in and controls for SO2 emissions.
In March 2011, the US EPA issued draft 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. EME is still evaluating the proposed standards but believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable without incurring material additional capital expenditures or operating costs for both the Midwest Generation plants and the Homer City plant. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and EME is unable at this time to assess potential costs of compliance, which could be significant for the Midwest Generation plants, but are not expected to be material for the Homer City plant, which already has cooling towers.
26
Note 11. Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) consisted of the following:
(in millions) |
Unrealized Gains (Losses) on Cash Flow Hedges |
Unrecognized Losses and Prior Service Adjustments, Net1 |
Accumulated Other Comprehensive Loss |
||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2010 |
$ | 16 | $ | (47 | ) | $ | (31 | ) | |||
Current period change |
(4 | ) | 1 | (3 | ) | ||||||
Balance at March 31, 2011 |
$ | 12 | $ | (46 | ) | $ | (34 | ) | |||
- 1
- For further detail, see Note 8Compensation and Benefit Plans.
Included in accumulated other comprehensive loss at March 31, 2011 was $21 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $9 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 $21 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.
Note 12. Supplemental Cash Flows Information
|
Three Months Ended March 31, |
|||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
||||||
Cash paid (received) |
||||||||
Interest (net of amount capitalized)1 |
$ | (4 | ) | $ | 3 | |||
Income taxes |
9 | 3 | ||||||
Cash payments under plant operating leases |
76 | 89 | ||||||
Non-cash activities from consolidation of variable interest entity |
||||||||
Assets |
$ | | $ | 94 | ||||
Liabilities |
| 99 | ||||||
Non-cash activities from deconsolidation of variable interest entities |
||||||||
Assets |
$ | | $ | 249 | ||||
Liabilities |
| 253 | ||||||
Non-cash activities from accrued capital expenditures |
$ | 38 | $ | 43 | ||||
- 1
- Interest paid for the three months ended March 31, 2011 was $6 million. Interest capitalized for the three months ended March 31, 2011 and 2010 was $10 million and $11 million, respectively.
27
Note 13. Discontinued Operations
Summarized financial information for discontinued operations is as follows:
|
Three Months Ended March 31, |
||||||
---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
|||||
Income (loss) before income taxes |
$ | (2 | ) | $ | 11 | ||
Provision for income taxes |
| 5 | |||||
Income (loss) from operations of discontinued foreign subsidiaries |
$ | (2 | ) | $ | 6 | ||
The 2011 loss was due primarily to changes in foreign exchange rates. The 2010 income was primarily attributable to the expiration of a contract indemnity.
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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. These statements reflect EME's current expectations and projections about future events based on EME'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 EME that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this quarterly report on Form 10-Q, 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 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 EME or its subsidiaries, include but are not limited to:
-
- EME's ability to borrow funds and access the capital markets on reasonable terms;
-
- environmental laws and regulations, at both state and federal levels, or changes in the application of those laws, that
could require additional expenditures or otherwise affect EME's cost and manner of doing business;
-
- supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale
markets to which EME's generating units have access;
-
- the cost and availability of fuel, sorbents, and other commodities used for power generation and emission controls, and of
related transportation services;
-
- the cost and availability of emission credits or allowances;
-
- transmission congestion in and to each market area and the resulting differences in prices between delivery points;
-
- the difficulty of predicting wholesale prices, transmission congestion, energy demand, and other aspects of the complex
and volatile markets in which EME and its subsidiaries participate;
-
- the availability and creditworthiness of counterparties, and the resulting effects on liquidity in the power and fuel
markets in which EME and its subsidiaries operate and/or the ability of counterparties to pay amounts owed to EME in excess of collateral provided in support of their obligations;
-
- governmental, statutory, regulatory or administrative changes or initiatives affecting EME or the electricity industry
generally, including the market structure rules applicable to each market and price mitigation strategies adopted by independent system operators and regional transmission organizations;
-
- market volatility and other market conditions that could increase EME's obligations to post collateral beyond the amounts currently expected, and the potential effect of such conditions on the ability of EME and its subsidiaries to provide sufficient collateral in support of their hedging activities and purchases of fuel;
29
-
- actions taken by Edison International and EME's directors, each of whom is appointed by Edison International, in the
interests of Edison International and its shareholders, which could include causing EME, subject to contractual obligations and applicable law, to distribute cash or assets or otherwise take actions
that may alter the portion of Edison International's portfolio of assets held and developed by EME;
-
- project development and acquisition risks, including those related to project site identification, financing,
construction, permitting, and governmental approvals;
-
- weather conditions, natural disasters and other unforeseen events;
-
- the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market
entrants, including the development of new generation facilities, and technologies that may be able to produce electricity at a lower cost than EME's generating facilities and/or increased access by
competitors to EME's markets as a result of transmission upgrades;
-
- operating risks, including equipment failure, availability, heat rate, output, costs of repairs and retrofits, and
availability and cost of spare parts;
-
- creditworthiness of suppliers and other project participants and their ability to deliver goods and services under their
contractual obligations to EME and its subsidiaries or to pay damages if they fail to fulfill those obligations;
-
- effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting
standards;
-
- general political, economic and business conditions;
-
- EME's continued participation and the continued participation by EME's subsidiaries in tax-allocation and
payment agreements with EME's respective affiliates; and
-
- EME's ability to attract and retain skilled people.
Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in "Item 1A. Risk Factors" on page 29 of EME's annual report on Form 10-K for the year ended December 31, 2010. Readers are urged to read this entire quarterly report on Form 10-Q and the annual report on Form 10-K for the year ended December 31, 2010, including the information incorporated by reference, and to carefully consider the risks, uncertainties and other factors that affect EME's business. Forward-looking statements speak only as of the date they are made, and EME is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by EME with the Securities and Exchange Commission.
This MD&A discusses material changes in the results of operations, financial condition and other developments of EME since December 31, 2010, and as compared to the first quarter ended March 31, 2010. This discussion presumes that the reader has read or has access to the MD&A included in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2010.
30
EME's competitive power generation business primarily consists of the generation and sale into the PJM market on a merchant basis of energy and capacity from its approximately 7,000 megawatts of coal-fired power plants. The profitability of these operations is expected to be significantly lower in 2011 as a result of lower realized energy prices driven by the expiration of hedge contracts, higher fuel costs and unplanned outages at the Homer City plant during the first quarter. In addition, the profitability of EME's Midwest Generation plants is expected to be adversely affected 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). For discussion of energy and fuel price risks, see "Market Risk ExposuresCommodity Price Risk" and refer to "Item 1A. Risk FactorsMarket Risks" on page 33 of EME's annual report on Form 10-K for the year ended December 31, 2010. As a result, EME may incur net losses during 2011 and in subsequent years unless energy prices recover or its costs decline.
Highlights of Operating Results
Net income (loss) attributable to EME common shareholder is composed of the following components:
|
Three Months Ended March 31, |
|
|||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
Change |
||||||||
Net income (loss) attributable to EME common shareholder |
$ | (20 | ) | $ | 81 | $ | (101 | ) | |||
Non-Core Items |
|||||||||||
Income (loss) from discontinued operations |
(2 | ) | 6 | (8 | ) | ||||||
Core Earnings (Losses) |
$ | (18 | ) | $ | 75 | $ | (93 | ) | |||
EME's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings (losses) internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with analysts and investors regarding EME's earnings results to facilitate comparisons of EME's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as net income (loss) attributable to EME's shareholder excluding income (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, sale of assets, early debt extinguishment costs, other activities that are no longer continuing, asset impairments, and certain tax, regulatory or legal proceedings.
EME's first quarter 2011 core earnings were lower than first quarter 2010 core earnings primarily due to the following pre-tax items:
-
- $32 million decrease in Midwest Generation adjusted operating income due to lower generation, lower average
realized energy prices and higher operating expenses partially offset by higher capacity revenue.
-
- $53 million decrease in Homer City adjusted operating income due primarily to lower generation resulting from the Unit 1 and 2 unplanned outages. Unit 1 returned to service in early April, and Unit 2 is expected to return to service during the second quarter of 2011.
31
-
- $32 million decrease in energy trading revenues due to lower congestion revenue and power trading revenue.
-
- $32 million lower income from distributions received from the March Point and Doga projects during the first quarter of 2010, with no comparable amounts in 2011.
Midwest Generation Environmental Compliance Plans and Costs
During the first quarter of 2011, Midwest Generation continued its permitting and planning activities for NOx and SO2 controls to meet the requirements of the CPS. In February 2011, the Illinois Environmental Protection Agency 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.
Decisions regarding whether or not to proceed with retrofitting units to comply with CPS requirements for SO2 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 it may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation intends to defer final decisions about particular units for the maximum time available. Accordingly, 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.
In March 2011, the US EPA issued draft "National Emission Standards for Hazardous Air Pollutants," limiting emissions of HAPs from coal- and oil-fired electrical generating units. The regulations are expected to be finalized by November 2011. Based on its continuing review, EME does not expect these standards, 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 NOx and SO2 as well as for HAPs, such as mercury, acid gas and non-mercury metals.
On February 10, 2011, a steam pipe ruptured at Unit 1 of the Homer City plant, taking the unit off line. Homer City took Unit 2 off line, which has the same design and operating conditions, to further evaluate the equipment due to the risk of a similar failure. On April 5, 2011, Unit 1 returned to service after making needed repairs, including replacing all pipes similar to the ruptured pipe. Unit 2 is undergoing similar repairs and is expected to return to service in the second quarter of 2011.
The unplanned outages at Units 1 and 2 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
32
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. The advance payments made and currently anticipated in April are expected to total approximately $30 million. It is currently anticipated that all such amounts will be applied against amounts invoiced by EMMT under an intercompany arrangement within the next six months, but the actual rate at which such advance payments will be applied will depend upon prevailing power prices and other factors. To further stabilize Homer City's liquidity, effective April 1, 2011, EMMT assigned to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. Accordingly, effective April 1, 2011, these revenues will now be 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 under the sale-leaseback documents at March 31, 2011. Under these documents, the rent payments are comprised of two components, a senior rent portion and an equity rent portion. The senior rent is used exclusively for debt service to the holders of the senior secured bonds issued in connection with the sale-leaseback transaction, while the equity rent is paid to the owner-lessors. In order to pay the equity portion of the 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).
For additional information, see "Liquidity and Capital ResourcesDividend Restrictions in Major Financings" and refer to "Liquidity Risks" on page 29 of EME's annual report on Form 10-K for the year ended December 31, 2010.
For information regarding recent developments in environmental regulations, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Environmental Developments."
At March 31, 2011, EME, as a holding company, had cash and cash equivalents of $391 million to meet liquidity needs as well as $484 million of capacity under its credit facility. EME's subsidiary, EMMT, also had cash and cash equivalents of $228 million at March 31, 2011, which can be loaned or distributed to EME subject to applicable laws. In addition, at March 31, 2011, Midwest Generation had cash and cash equivalents of $363 million to meet liquidity needs.
Midwest Generation has not yet committed to the completion of environmental compliance activities for all of its plants. Additional expenditures for NOx and SO2 controls through 2013 are estimated at $567 million based on an assumption that Midwest Generation would retrofit all units over the compliance period, which extends to 2018. Depending upon the facilities selected to be retrofitted, the cost of such retrofitting, and the timing of funding requirements beyond the near term, Midwest Generation may utilize operating cash flow, draw on its credit facilities, when available, or seek debt financing to fund capital expenditures.
Capital expenditures to complete renewable energy projects for the remainder of 2011 are projected to be $216 million at March 31, 2011. EME anticipates that capital investment for renewable energy projects under construction will be funded using a combination of construction and term financings,
33
U.S. Treasury grants and cash on hand. In addition, U.S. Treasury grants of $367 million are anticipated based on estimated eligible construction costs for renewable projects completed or scheduled to be completed in 2011. To the extent that the renewable projects supporting these investments and capitalized assets are not successful, EME would incur a material charge.
Edison International's utilization of net operating losses and production tax credits from EME in its consolidated return impacts EME's liquidity. The bonus depreciation extension enacted in the Small Business Jobs Act of 2010 and the 2010 Tax Relief Act is expected to result in delays in EME's receipt of future tax-allocation payments. For more information, see "Liquidity and Capital ResourcesEME's Liquidity as a Holding CompanyIntercompany Tax-Allocation Agreement," "Liquidity and Capital ResourcesAvailable LiquidityBonus Depreciation Impact on EME" and refer to "Item 1A. Risk FactorsLiquidity Risks" on page 29 of EME's annual report on Form 10-K for the year ended December 31, 2010.
34
Results of Continuing Operations
EME operates in one line of business, independent power production. The following section and table provide a summary of results of EME's operating projects and corporate expenses for the first quarters of 2011 and 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.
The following table shows the adjusted operating income (loss) (AOI) of EME's projects:
|
Three Months Ended March 31, |
||||||
---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
|||||
Midwest Generation plants |
$ | 55 | $ | 87 | |||
Homer City plant1 |
(16 | ) | 37 | ||||
Renewable energy projects |
21 | 10 | |||||
Energy trading1 |
15 | 47 | |||||
Big 4 projects |
2 | 4 | |||||
Sunrise |
(7 | ) | (4 | ) | |||
Doga |
| 15 | |||||
March Point2 |
| 17 | |||||
Westside projects |
| 1 | |||||
Other projects |
4 | 3 | |||||
Other operating income (expense) |
| 2 | |||||
|
74 | 219 | |||||
Corporate administrative and general |
(34 | ) | (36 | ) | |||
Corporate depreciation and amortization |
(6 | ) | (4 | ) | |||
AOI3 |
$ | 34 | $ | 179 | |||
- 1
- Effective
April 1, 2011, EMMT assigned to Homer City the benefit of an arrangement that allows EMMT to deliver power into
the NYISO from Homer City.
- 2
- Sold
in 2010.
- 3
- AOI is equal to operating income (loss) under GAAP, plus equity in income (loss) of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests in AOI is meaningful for investors as these components are integral to the operating results of EME.
35
The following table reconciles AOI to operating income as reflected on EME's consolidated statements of operations:
|
Three Months Ended March 31, |
|||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
||||||
AOI |
$ | 34 | $ | 179 | ||||
Less: |
||||||||
Equity in income (loss) of unconsolidated affiliates |
(5 | ) | 17 | |||||
Dividend income from projects |
1 | 16 | ||||||
Production tax credits |
18 | 14 | ||||||
Other income, net |
3 | 2 | ||||||
Operating Income |
$ | 17 | $ | 130 | ||||
Adjusted Operating Income from Consolidated Operations
The following table presents additional data for the Midwest Generation plants:
|
Three Months Ended March 31, |
||||||||
---|---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
|||||||
Operating Revenues |
$ | 351 | $ | 379 | |||||
Operating Expenses |
|||||||||
Fuel1 |
126 | 141 | |||||||
Plant operations |
118 | 99 | |||||||
Plant operating leases |
19 | 19 | |||||||
Depreciation and amortization |
29 | 28 | |||||||
Administrative and general |
6 | 5 | |||||||
Total operating expenses |
298 | 292 | |||||||
Operating Income |
53 | 87 | |||||||
Other Income |
2 | | |||||||
AOI |
$ | 55 | $ | 87 | |||||
Statistics2 |
|||||||||
Generation (in GWh) |
7,470 | 8,212 | |||||||
Aggregate plant performance |
|||||||||
Equivalent availability |
87.0% | 85.9% | |||||||
Capacity factor |
67.0% | 69.6% | |||||||
Load factor |
77.0% | 81.1% | |||||||
Forced outage rate |
5.1% | 6.7% | |||||||
Average realized price/MWh |
$ | 36.65 | $ | 39.52 | |||||
Capacity revenues only (in millions) |
$ | 77 | $ | 47 | |||||
Average realized fuel costs/MWh |
$ | 16.73 | $ | 16.63 | |||||
- 1
- Included in fuel costs were $2 million and $4 million during the quarters ended March 31, 2011 and 2010, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of NOx emission allowances
36
to Midwest Generation were $0.4 million during each of the first quarters of 2011 and 2010. Transfers of SO2 emission allowances from Midwest Generation were none and $4 million during the first quarters of 2011 and 2010, respectively. For more information regarding the price of emission allowances, see "Market Risk ExposuresCommodity Price RiskEmission Allowances Price Risk."
- 2
- For an explanation of how the statistical data is determined, see "Reconciliation of Non-GAAP DisclosuresCoal Plants and Statistical Definitions."
AOI from the Midwest Generation plants decreased $32 million for the first quarter of 2011, compared to the first quarter 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 primarily related 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 of none and $7 million for the first quarters of 2011 and 2010, respectively. Unrealized gains in 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 $5 million during the first quarters of 2011 and 2010, respectively, 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.
37
The following table presents additional data for the Homer City plant:
|
Three Months Ended March 31, |
|||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
||||||
Operating Revenues |
$ | 115 | $ | 175 | ||||
Operating Expenses |
||||||||
Fuel1 |
52 | 70 | ||||||
Plant operations |
47 | 37 | ||||||
Plant operating leases |
25 | 25 | ||||||
Depreciation and amortization |
5 | 5 | ||||||
Administrative and general |
2 | 1 | ||||||
Total operating expenses |
131 | 138 | ||||||
Operating Income (Loss) |
(16 | ) | 37 | |||||
AOI |
$ | (16 | ) | $ | 37 | |||
Statistics2 |
||||||||
Generation (in GWh) |
1,943 | 2,954 | ||||||
Equivalent availability |
59.2% | 80.2% | ||||||
Capacity factor |
47.8% | 72.4% | ||||||
Load factor |
80.7% | 90.3% | ||||||
Forced outage rate |
27.1% | 10.4% | ||||||
Average realized energy price/MWh |
$ | 45.31 | $ | 50.17 | ||||
Capacity revenues only (in millions) |
$ | 24 | $ | 29 | ||||
Average fuel costs/MWh |
$ | 26.96 | $ | 23.57 | ||||
- 1
- Included
in fuel costs were $0.3 million and $4 million during the quarters ended March 31, 2011 and 2010,
respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of
SO2 emission allowances to Homer City were none and $4 million during the first quarters of 2011 and 2010, respectively. Transfers of NOx emission
allowances from Homer City were $0.4 million during each of the first quarters of 2011 and 2010. For more information regarding the price of emission allowances, see "Market Risk
ExposuresCommodity Price RiskEmission Allowances Price Risk."
- 2
- For an explanation of how the statistical data is determined, see "Reconciliation of Non-GAAP DisclosuresCoal Plants and Statistical Definitions."
AOI from the Homer City plant decreased $53 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease in AOI was attributable to lower energy revenues, driven by lower generation, and higher plant maintenance costs from unplanned outages at Units 1 and 2, partially offset by lower fuel costs. The decline in fuel costs was primarily 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 $(2) million for the first quarters of 2011 and 2010, respectively. Unrealized gains (losses) 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. 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
38
busbar (the delivery point where power generated by the Homer City plant is delivered into the transmission system).
Reconciliation of Non-GAAP DisclosuresCoal Plants and Statistical Definitions
The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenues less unrealized gains (losses) and other non-energy related revenues by (ii) generation as shown in the table below. Revenues related to capacity sales are excluded from the calculation of average realized energy price.
|
Three Months Ended March 31, |
|||||||
---|---|---|---|---|---|---|---|---|
Midwest Generation Plants (in millions) |
||||||||
2011 |
2010 |
|||||||
Operating revenues |
$ | 351 | $ | 379 | ||||
Less: |
||||||||
Unrealized gains |
| (7 | ) | |||||
Capacity and other revenues |
(77 | ) | (48 | ) | ||||
Realized revenues |
$ | 274 | $ | 324 | ||||
Generation (in GWh) |
7,470 | 8,212 | ||||||
Average realized energy price/MWh |
$ |
36.65 |
$ |
39.52 |
||||
|
Three Months Ended March 31, |
|||||||
---|---|---|---|---|---|---|---|---|
Homer City Plant (in millions) |
||||||||
2011 |
2010 |
|||||||
Operating revenues |
$ | 115 | $ | 175 | ||||
Less: |
||||||||
Unrealized (gains) losses |
(2 | ) | 2 | |||||
Capacity and other revenues |
(25 | ) | (29 | ) | ||||
Realized revenues |
$ | 88 | $ | 148 | ||||
Generation (in GWh) |
1,943 | 2,954 | ||||||
Average realized energy price/MWh |
$ |
45.31 |
$ |
50.17 |
||||
The average realized energy price is presented as an aid in understanding the operating results of the coal plants. Average realized energy price is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as operating revenues. Management believes that the average realized energy price is meaningful for investors as this information reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons or as compared to
39
real-time market prices. A reconciliation of the operating revenues of the coal plants and renewable energy projects to consolidated operating revenues presented in the preceding table is set forth below:
|
Three Months Ended March 31, |
|||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
||||||
Operating revenues |
||||||||
Midwest Generation plants |
$ | 351 | $ | 379 | ||||
Homer City plant |
115 | 175 | ||||||
Renewable energy projects |
52 | 30 | ||||||
Other revenues |
32 | 67 | ||||||
Consolidated operating revenues as reported |
$ | 550 | $ | 651 | ||||
The average realized fuel costs reflect the average cost per MWh at which fuel is consumed for generation sold into the market, including emission allowance costs and the effects of hedges. It is determined by dividing (i) fuel costs adjusted for unrealized gains (losses) by (ii) generation as shown in the table below:
|
Three Months Ended March 31, | |||||||
---|---|---|---|---|---|---|---|---|
Midwest Generation Plants (in millions) |
||||||||
2011 |
2010 |
|||||||
Fuel costs |
$ | 126 | $ | 141 | ||||
Less: |
||||||||
Unrealized losses |
(1 | ) | (5 | ) | ||||
Realized fuel costs |
$ | 125 | $ | 136 | ||||
Generation (in GWh) |
7,470 | 8,212 | ||||||
Average realized fuel costs/MWh |
$ |
16.73 |
$ |
16.63 |
||||
The average realized fuel costs are presented as an aid in understanding the operating results of the Midwest Generation plants. Average realized fuel costs are a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as fuel costs. Management believes that average realized fuel costs are meaningful for investors as this information reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons. A reconciliation of the fuel costs of the coal plants to consolidated fuel costs presented in the preceding table is set forth below:
|
Three Months Ended March 31, | |||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2011 |
2010 |
||||||
Fuel costs |
||||||||
Midwest Generation plants |
$ | 126 | $ | 141 | ||||
Homer City plant |
52 | 70 | ||||||
Other |
4 | 2 | ||||||
Consolidated fuel costs as reported |
$ | 182 | $ | 213 | ||||
40