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TABLE OF CONTENTS
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark one) | ||
ý |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
|
For the Quarterly Period Ended June 30, 2010 |
||
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.) |
|
18101 Von Karman Avenue, Suite 1700 Irvine, California (Address of principal executive offices) |
92612 (Zip Code) |
Registrant's telephone number, including area code: (949) 752-5588
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 August 5, 2010: 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.
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 | |
Commonwealth Edison | Commonwealth Edison Company | |
CPS | Combined Pollutant Standard | |
EME | Edison Mission Energy | |
Homer City | EME Homer City Generation L.P. | |
EMMT | Edison Mission Marketing & Trading, Inc. | |
FASB | Financial Accounting Standards Board | |
FGD | flue gas desulfurization | |
Fossil-fueled facilities | Midwest Generation fossil-fueled power plants and Homer City electric generating station | |
GAAP | United States generally accepted accounting principles | |
GHG | greenhouse gas | |
GWh | gigawatt-hours | |
Illinois EPA | Illinois Environmental Protection Agency | |
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 | |
NAAQS | National Ambient Air Quality Standards | |
NOV | Notice of Violation | |
NOX | nitrogen oxide | |
PJM | PJM Interconnection, LLC | |
PRB | Powder River Basin | |
PSD | Prevention of Significant Deterioration | |
RPM | Reliability Pricing Model | |
S&P | Standard & Poor's Ratings Services | |
SNCR | selective non-catalytic reduction | |
SO2 | sulfur dioxide | |
US EPA | United States Environmental Protection Agency | |
v
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS) (in millions, unaudited) |
|||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||
|
2010 |
2009 |
2010 |
2009 |
|||||||||||
Operating Revenues |
$ | 493 | $ | 557 | $ | 1,144 | $ | 1,169 | |||||||
Operating Expenses |
|||||||||||||||
Fuel |
161 | 172 | 374 | 359 | |||||||||||
Plant operations |
229 | 146 | 388 | 296 | |||||||||||
Plant operating leases |
45 | 44 | 89 | 88 | |||||||||||
Depreciation and amortization |
60 | 56 | 119 | 112 | |||||||||||
Administrative and general |
44 | 51 | 90 | 95 | |||||||||||
Total operating expenses |
539 | 469 | 1,060 | 950 | |||||||||||
Operating income (loss) |
(46 |
) |
88 |
84 |
219 |
||||||||||
Other Income (Expense) |
|||||||||||||||
Equity in income from unconsolidated affiliates |
20 | 21 | 39 | 28 | |||||||||||
Dividend income |
1 | 9 | 17 | 10 | |||||||||||
Interest income |
1 | 3 | 2 | 6 | |||||||||||
Interest expense |
(66 | ) | (73 | ) | (134 | ) | (147 | ) | |||||||
Total other expense |
(44 |
) |
(40 |
) |
(76 |
) |
(103 |
) |
|||||||
Income (loss) from continuing operations before income taxes |
(90 |
) |
48 |
8 |
116 |
||||||||||
Provision (benefit) for income taxes |
(70 | ) | 2 | (47 | ) | 17 | |||||||||
Income (Loss) from Continuing Operations |
(20 |
) |
46 |
55 |
99 |
||||||||||
Income (Loss) from Operations of Discontinued Subsidiaries, net of tax (Note 5) |
3 | (7 | ) | 9 | (4 | ) | |||||||||
Net Income (Loss) |
(17 |
) |
39 |
64 |
95 |
||||||||||
Net (Income) Loss Attributable to Noncontrolling Interests |
|
1 |
|
1 |
|||||||||||
Net Income (Loss) Attributable to EME Common Shareholders |
$ |
(17 |
) |
$ |
40 |
$ |
64 |
$ |
96 |
||||||
Amounts Attributable to EME Common Shareholders |
|||||||||||||||
Income (loss) from continuing operations, net of tax |
$ | (20 | ) | $ | 47 | $ | 55 | $ | 100 | ||||||
Income (loss) from discontinued operations, net of tax |
3 | (7 | ) | 9 | (4 | ) | |||||||||
Net Income (Loss) Attributable to EME Common Shareholders |
$ |
(17 |
) |
$ |
40 |
$ |
64 |
$ |
96 |
||||||
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 June 30, |
Six Months Ended June 30, |
|||||||||||||
|
2010 |
2009 |
2010 |
2009 |
|||||||||||
Net Income (Loss) |
$ | (17 | ) | $ | 39 | $ | 64 | $ | 95 | ||||||
Other comprehensive income (loss), net of tax |
|||||||||||||||
Pension and postretirement benefits other than pensions: |
|||||||||||||||
Amortization of net loss and prior service adjustment included in expense, net of tax |
| 1 | | 1 | |||||||||||
Unrealized gains (losses) on derivatives qualified as cash flow hedges: |
|||||||||||||||
Unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(50) and $(50) for the three months and $12 and $48 for the six months ended June 30, 2010 and 2009, respectively |
(77 | ) | (90 | ) | 18 | 61 | |||||||||
Reclassification adjustments included in net income, net of income tax expense (benefit) of $(35) and $9 for the three months and $(49) and $(23) for the six months ended June 30, 2010 and 2009, respectively |
(53 | ) | 17 | (73 | ) | (32 | ) | ||||||||
Other comprehensive income (loss) |
(130 |
) |
(72 |
) |
(55 |
) |
30 |
||||||||
Comprehensive Income (Loss) |
(147 |
) |
(33 |
) |
9 |
125 |
|||||||||
Comprehensive Loss Attributable to Noncontrolling Interests |
|
1 |
|
1 |
|||||||||||
Comprehensive Income (Loss) Attributable to EME Common Shareholders |
$ |
(147 |
) |
$ |
(32 |
) |
$ |
9 |
$ |
126 |
|||||
The accompanying notes are an integral part of these consolidated financial statements.
2
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (in millions, unaudited) |
|||||||||
---|---|---|---|---|---|---|---|---|---|
|
June 30, 2010 |
December 31, 2009 |
|||||||
Assets |
|||||||||
Current Assets |
|||||||||
Cash and cash equivalents |
$ | 707 | $ | 796 | |||||
Accounts receivabletrade |
151 | 201 | |||||||
Receivables from affiliates |
92 | 93 | |||||||
Inventory |
234 | 196 | |||||||
Derivative assets |
146 | 197 | |||||||
Restricted cash |
25 | 69 | |||||||
Margin and collateral deposits |
108 | 120 | |||||||
Prepaid expenses and other |
50 | 190 | |||||||
Total current assets |
1,513 |
1,862 |
|||||||
Investments in Unconsolidated Affiliates |
508 |
361 |
|||||||
Property, Plant and Equipment |
6,670 |
6,279 |
|||||||
Less accumulated depreciation and amortization |
1,629 | 1,474 | |||||||
Net property, plant and equipment |
5,041 |
4,805 |
|||||||
Other Assets |
|||||||||
Deferred financing costs |
50 | 43 | |||||||
Long-term derivative assets |
79 | 81 | |||||||
Restricted deposits |
42 | 40 | |||||||
Rent payments in excess of levelized rent expense under plant operating leases |
1,149 | 1,038 | |||||||
Other long-term assets |
259 | 403 | |||||||
Total other assets |
1,579 |
1,605 |
|||||||
Total Assets |
$ |
8,641 |
$ |
8,633 |
|||||
The accompanying notes are an integral part of these consolidated financial statements.
3
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (in millions, unaudited) |
|||||||||
---|---|---|---|---|---|---|---|---|---|
|
June 30, 2010 |
December 31, 2009 |
|||||||
Liabilities and Shareholder's Equity |
|||||||||
Current Liabilities |
|||||||||
Accounts payable |
$ | 100 | $ | 97 | |||||
Payables to affiliates |
5 | 14 | |||||||
Accrued liabilities |
162 | 247 | |||||||
Derivative liabilities |
| 5 | |||||||
Interest payable |
30 | 30 | |||||||
Deferred taxes |
91 | 119 | |||||||
Current maturities of long-term obligations |
42 | 37 | |||||||
Construction loan |
65 | | |||||||
Total current liabilities |
495 |
549 |
|||||||
Long-term obligations net of current maturities |
3,979 |
3,929 |
|||||||
Deferred taxes and tax credits |
714 | 672 | |||||||
Deferred revenues |
163 | 153 | |||||||
Long-term derivative liabilities |
23 | 15 | |||||||
Other long-term liabilities |
486 | 478 | |||||||
Total Liabilities |
5,860 |
5,796 |
|||||||
Commitments and Contingencies (Note 10) |
|||||||||
Equity |
|||||||||
Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of June 30, 2010 and December 31, 2009 |
64 | 64 | |||||||
Additional paid-in capital |
1,337 | 1,339 | |||||||
Retained earnings |
1,352 | 1,280 | |||||||
Accumulated other comprehensive income |
23 | 78 | |||||||
Total EME common shareholder's equity |
2,776 |
2,761 |
|||||||
Noncontrolling Interests |
5 |
76 |
|||||||
Total Equity |
2,781 |
2,837 |
|||||||
Total Liabilities and Equity |
$ |
8,641 |
$ |
8,633 |
|||||
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) |
|||||||||
---|---|---|---|---|---|---|---|---|---|
|
Six Months Ended June 30, |
||||||||
|
2010 |
2009 |
|||||||
Cash Flows From Operating Activities |
|||||||||
Net income |
$ | 64 | $ | 95 | |||||
(Income) loss from discontinued operations |
(9 | ) | 4 | ||||||
Income from continuing operations, net |
55 | 99 | |||||||
Adjustments to reconcile income to net cash provided by (used in) operating activities: |
|||||||||
Equity in income from unconsolidated affiliates |
(37 | ) | (26 | ) | |||||
Distributions from unconsolidated affiliates |
39 | 21 | |||||||
Depreciation and amortization |
125 | 115 | |||||||
Deferred taxes and tax credits |
53 | 209 | |||||||
Changes in operating assets and liabilities: |
|||||||||
Decrease (increase) in margin and collateral deposits |
12 | (12 | ) | ||||||
Decrease (increase) in accounts receivables |
53 | (127 | ) | ||||||
Increase in inventory |
(34 | ) | (31 | ) | |||||
Decrease in prepaid expenses and other |
7 | 36 | |||||||
Decrease (increase) in restricted cash |
43 | (188 | ) | ||||||
Increase in rent payments in excess of levelized rent expense |
(111 | ) | (113 | ) | |||||
Decrease in accounts payable and other current liabilities |
(121 | ) | (144 | ) | |||||
Increase in derivative assets and liabilities |
(35 | ) | (1 | ) | |||||
Proceeds from U.S. Treasury grants |
92 | | |||||||
Other operatingassets |
8 | (1 | ) | ||||||
Other operatingliabilities |
10 | 72 | |||||||
Operating cash flow from continuing operations |
159 | (91 | ) | ||||||
Operating cash flow from discontinued operations |
9 | (4 | ) | ||||||
Net cash provided by (used in) operating activities |
168 | (95 | ) | ||||||
Cash Flows From Financing Activities |
|||||||||
Borrowings on long-term debt |
7 | 189 | |||||||
Payments on long-term debt agreements |
(23 | ) | (43 | ) | |||||
Borrowings under construction loan |
65 | | |||||||
Payments to affiliates related to stock-based awards |
(2 | ) | (1 | ) | |||||
Financing costs |
(10 | ) | (13 | ) | |||||
Net cash provided by financing activities |
37 | 132 | |||||||
Cash Flows From Investing Activities |
|||||||||
Capital expenditures |
(313 | ) | (138 | ) | |||||
Proceeds from return of capital and loan repayments and sale of assets |
27 | 11 | |||||||
Purchase of interest of acquired companies |
(4 | ) | (7 | ) | |||||
Maturities of short-term investments |
1 | 2 | |||||||
Increase in restricted cash |
| (1 | ) | ||||||
Investments in other assets |
(5 | ) | (55 | ) | |||||
Net cash used in investing activities |
(294 | ) | (188 | ) | |||||
Net decrease in cash and cash equivalents |
(89 | ) | (151 | ) | |||||
Cash and cash equivalents at beginning of period |
796 | 1,807 | |||||||
Cash and cash equivalents at end of period |
$ | 707 | $ | 1,656 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
5
EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2010
(Unaudited)
Note 1. Summary of Significant Accounting Policies
EME's significant accounting policies were described in "Note 1Summary of Significant Accounting Policies" on page 114 of EME's annual report on Form 10-K for the year ended December 31, 2009. EME follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2010 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 six months ended June 30, 2010 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.
Cash and cash equivalents consisted of the following:
(in millions) |
June 30, 2010 |
December 31, 2009 |
|||||
---|---|---|---|---|---|---|---|
Cash |
$ | 212 | $ | 106 | |||
Money market funds |
495 | 690 | |||||
Total cash and cash equivalents |
$ | 707 | $ | 796 | |||
The carrying value of cash equivalents, which consists of money market funds, equals the fair value as all investments have maturities of less than three months. For further discussion of money market funds, see Note 2Fair Value Measurements.
6
Inventory is stated at the lower of weighted average cost or market. Inventory consisted of the following:
(in millions) |
June 30, 2010 |
December 31, 2009 |
|||||
---|---|---|---|---|---|---|---|
Coal, fuel oil and other raw materials |
$ | 166 | $ | 132 | |||
Spare parts, materials and supplies |
68 | 64 | |||||
Total |
$ | 234 | $ | 196 | |||
Accounting Guidance Adopted in 2010
ConsolidationImprovements to Financial Reporting by Enterprises Involved with Variable Interest Entities
The FASB issued an accounting standards update that changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an ability to direct the activities of the entity that most significantly impact the entity's economic performance and whether the entity has the obligation to absorb losses or the right to receive expected returns of the entity. This guidance requires a company to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. EME adopted this guidance effective January 1, 2010. The impact of adopting this guidance resulted in the deconsolidation of certain wind assets totaling $253 million and the consolidation of coal assets totaling $99 million at January 1, 2010. Deconsolidation did not result in a gain or loss. The consolidation of EME's 50% partnership interest in American Bituminous Power Partners, L.P., referred to as the Ambit project, a coal-fired electrical plant project with a capacity of 80 MW, resulted in a cumulative effect adjustment that increased retained earnings by $10 million. For further discussion, see Note 7Variable Interest Entities.
Fair Value Measurements and Disclosures
The FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. Requirements, effective January 1, 2010, include separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The update also clarified existing disclosure requirements for the level of disaggregation, inputs and valuation techniques. In addition, effective January 1, 2011, the Level 3 reconciliation of fair value measurements using significant unobservable inputs should include gross rather than net information about purchases, sales, issuances and settlements. The guidance impacts disclosures only. For further discussion, see Note 2Fair Value Measurements.
Accounting Guidance Not Yet Adopted
In October 2009, the FASB issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and
7
recognizing revenue 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 effective beginning January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. EME is currently assessing the effects this guidance may have on its consolidated financial statements.
Note 2. 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 for a liability should reflect the entity's nonperformance risk. Fair value is determined using a hierarchy to prioritize inputs to valuation models. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are:
EME's assets and liabilities carried at fair value primarily consist of derivative contracts and money market funds. Derivative contracts are primarily commodity contracts for the purchase and sale of power and include contracts for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange or over-the-counter traded.
The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. Investments in money market funds are generally classified as Level 1 as fair value is determined by observable market prices in active markets.
Derivative contracts, valued based on forward market prices in active markets (PJM West Hub, Northern Illinois Hub peak and AEP/Dayton) adjusted for nonperformance risks, are classified as Level 2. EME obtains forward market prices from traded exchanges (Intercontinental Exchange Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EME selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EME believes to provide the most liquid market for the commodity. EME considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers, and comparison to executed trades.
8
Financial transmission rights and over-the-counter derivatives that trade infrequently at illiquid locations, and long-term power agreements are classified as Level 3. For illiquid financial transmission rights, EME reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts fair value when EME concludes a change in objective criteria would result in a new valuation that better reflects fair value. Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity 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. 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. Derivative contracts with counterparties that have significant nonperformance risks are classified as Level 3.
In assessing nonperformance risks, EME reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of nonperformance. The fair value of derivative assets nonperformance risk was $3 million at June 30, 2010.
9
The following table sets forth EME's assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:
|
As of June 30, 2010 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Level 1 |
Level 2 |
Level 3 |
Netting and Collateral2 |
Total |
|||||||||||||
Assets at Fair Value |
||||||||||||||||||
Money market funds1 |
$ | 521 | $ | | $ | | $ | | $ | 521 | ||||||||
Derivatives |
||||||||||||||||||
Electricity |
$ | | $ | 142 | $ | 171 | $ | (88 | ) | $ | 225 | |||||||
Natural gas |
2 | | | (2 | ) | | ||||||||||||
Fuel oil |
8 | | | (8 | ) | | ||||||||||||
Total commodity contracts |
10 | 142 | 171 | (98 | ) | 225 | ||||||||||||
Total derivatives |
$ | 10 | $ | 142 | $ | 171 | $ | (98 | ) | $ | 225 | |||||||
Liabilities at Fair Value |
||||||||||||||||||
Derivatives |
||||||||||||||||||
Electricity |
$ | | $ | (68 | ) | $ | (5 | ) | $ | 69 | $ | (4 | ) | |||||
Natural gas |
(1 | ) | (2 | ) | | 1 | (2 | ) | ||||||||||
Total commodity contracts |
(1 | ) | (70 | ) | (5 | ) | 70 | (6 | ) | |||||||||
Interest rate contracts |
| (17 | ) | | | (17 | ) | |||||||||||
Total derivatives |
$ | (1 | ) | $ | (87 | ) | $ | (5 | ) | $ | 70 | $ | (23 | ) | ||||
As of December 31, 2009 |
||||||||||||||||||
Assets at Fair Value |
||||||||||||||||||
Money market funds1 |
$ | 758 | $ | | $ | | $ | | $ | 758 | ||||||||
Derivatives |
||||||||||||||||||
Electricity |
$ | | $ | 235 | $ | 179 | $ | (136 | ) | $ | 278 | |||||||
Natural gas |
2 | | | (2 | ) | | ||||||||||||
Fuel oil |
15 | | | (15 | ) | | ||||||||||||
Total commodity contracts |
17 | 235 | 179 | (153 | ) | 278 | ||||||||||||
Total derivatives |
$ | 17 | $ | 235 | $ | 179 | $ | (153 | ) | $ | 278 | |||||||
Liabilities at Fair Value |
||||||||||||||||||
Derivatives |
||||||||||||||||||
Electricity |
$ | | $ | (85 | ) | $ | (6 | ) | $ | 73 | $ | (18 | ) | |||||
Natural gas |
(3 | ) | (1 | ) | | 4 | | |||||||||||
Total commodity contracts |
(3 | ) | (86 | ) | (6 | ) | 77 | (18 | ) | |||||||||
Interest rate contracts |
| (2 | ) | | | (2 | ) | |||||||||||
Total derivatives |
$ | (3 | ) | $ | (88 | ) | $ | (6 | ) | $ | 77 | $ | (20 | ) | ||||
10
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 June 30, | Six Months Ended June 30, | ||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | ||||||||||||||||
(in millions) |
Deriva- tives |
Deriva- tives |
Money Market Funds |
Deriva- tives |
Deriva- tives |
Money Market Funds |
||||||||||||||
Fair value at beginning of periods |
$ | 199 | $ | 267 | $ | 2 | $ | 173 | $ | 213 | $ | 3 | ||||||||
Total realized/unrealized gains (losses) |
||||||||||||||||||||
Included in earnings1 |
(18 | ) | (49 | ) | | 27 | 97 | | ||||||||||||
Included in accumulated other comprehensive income (loss) |
(2 | ) | | | 4 | | | |||||||||||||
Purchases and settlements, net |
(19 | ) | 30 | (1 | ) | (43 | ) | (58 | ) | (2 | ) | |||||||||
Transfers in or out of Level 3 |
6 | (8 | ) | | 5 | (12 | ) | | ||||||||||||
Fair value at June 30 |
$ | 166 | $ | 240 | $ | 1 | $ | 166 | $ | 240 | $ | 1 | ||||||||
Change during the periods in unrealized gains (losses) related to assets and liabilities, net held at June 301 |
$ | (2 | ) | $ | 13 | $ | | $ | 32 | $ | 71 | $ | | |||||||
EME determines the fair value of transfers in and transfers out of each level at the end of each reporting period. Level 1 had no transfers in and out during the second quarters and six months ended June 30, 2010 and 2009. Transfers in and out of Level 2 were not significant during the second quarters and six months ended June 30, 2010 and 2009.
The carrying amounts and fair values of EME's long-term obligations were as follows:
|
As of June 30, 2010 | As of December 31, 2009 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
|||||||||
Long-term obligations, including current portion |
$ | 4,021 | $ | 2,732 | $ | 3,966 | $ | 3,150 | |||||
In assessing the fair value of EME's long-term obligations, 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 value of trade receivables, payables and construction loan approximates fair value and, therefore, is not included in the table above.
Note 3. Derivative Instruments and Risk Management
EME uses derivative instruments to reduce EME's exposure to market risks that arise from fluctuations in prices of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. To the extent that EME does not use
11
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 in the consolidated statements of income (loss). For transactions that qualify for accounting hedge 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 income until the related forecasted transaction occurs.
Derivative instruments that are utilized for trading purposes are measured at fair value and included in the balance sheet as derivative assets or liabilities. Changes in fair value are recognized in the consolidated statements of income (loss).
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging and trading activities:
June 30, 2010 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
Hedging Activities | |
|||||||||||
Commodity |
Instrument |
Classification |
Unit of Measure |
Cash Flow Hedges |
Economic Hedges |
Trading Activities |
||||||||||
Electricity |
Forwards/Futures | Sales | GWh | 29,884 | 1 | 19,257 | 3 | 33,785 | ||||||||
Electricity |
Forwards/Futures | Purchases | GWh | 408 | 1 | 18,698 | 3 | 36,700 | ||||||||
Electricity |
Capacity | Sales | MW-Day (in thousands) | 183 | 2 | | 218 | 2 | ||||||||
Electricity |
Capacity | Purchases | MW-Day (in thousands) | 17 | 2 | | 557 | 2 | ||||||||
Electricity |
Congestion | Sales | GWh | | 136 | 4 | 8,964 | 4 | ||||||||
Electricity |
Congestion | Purchases | GWh | | 1,362 | 4 | 195,038 | 4 | ||||||||
Natural gas |
Forwards/Futures | Sales | bcf | | 1.5 | 45.0 | ||||||||||
Natural gas |
Forwards/Futures | Purchases | bcf | | | 47.9 | ||||||||||
Fuel oil |
Forwards/Futures | Sales | barrels | | 120,000 | 319,000 | ||||||||||
Fuel oil |
Forwards/Futures | Purchases | barrels | | 495,000 | 329,000 | ||||||||||
Coal |
Forwards/Futures | Sales | tons | | | 1,095,000 | ||||||||||
Coal |
Forwards/Futures | Purchases | tons | | | 465,000 | ||||||||||
(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 | $ | 145 | 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 |
|||||
12
December 31, 2009 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|
|
|
Hedging Activities | |
|||||||||||
Commodity |
Instrument |
Classification |
Unit of Measure |
Cash Flow Hedges |
Economic Hedges |
Trading Activities |
||||||||||
Electricity |
Forwards/Futures | Sales | GWh | 24,355 | 1 | 26,838 | 3 | 23,306 | ||||||||
Electricity |
Forwards/Futures | Purchases | GWh | 106 | 1 | 25,971 | 3 | 23,404 | ||||||||
Electricity |
Capacity | Sales | MW-Day (in thousands) | 254 | 2 | 1 | 2 | 597 | 2 | |||||||
Electricity |
Capacity | Purchases | MW-Day (in thousands) | 11 | 2 | 2 | 2 | 736 | 2 | |||||||
Electricity |
Congestion | Sales | GWh | | 136 | 4 | 10,212 | 4 | ||||||||
Electricity |
Congestion | Purchases | GWh | | 1,576 | 4 | 181,930 | 4 | ||||||||
Natural gas |
Forwards/Futures | Sales | bcf | | 3.3 | 30.8 | ||||||||||
Natural gas |
Forwards/Futures | Purchases | bcf | | | 30.6 | ||||||||||
Fuel oil |
Forwards/Futures | Sales | barrels | | 250,000 | 120,000 | ||||||||||
Fuel oil |
Forwards/Futures | Purchases | barrels | | 625,000 | 120,000 | ||||||||||
(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 | $ | 160 | June 2016 | ||||
13
Fair Value of Derivative Instruments
The following table summarizes the fair value of derivative instruments reflected on EME's consolidated balance sheets:
June 30, 2010 | |||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Derivative Assets | Derivative Liabilities | |
||||||||||||||||||||
(in millions) |
Short-term |
Long-term |
Subtotal |
Short-term |
Long-term |
Subtotal |
Net Assets |
||||||||||||||||
Non-trading activities |
|||||||||||||||||||||||
Cash flow hedges |
$ | 153 | $ | 14 | $ | 167 | $ | 39 | $ | 43 | $ | 82 | $ | 85 | |||||||||
Economic hedges |
111 | 3 | 114 | 93 | 2 | 95 | 19 | ||||||||||||||||
Trading activities |
237 | 121 | 358 | 182 | 50 | 232 | 126 | ||||||||||||||||
|
501 | 138 | 639 | 314 | 95 | 409 | 230 | ||||||||||||||||
Netting and collateral received1 |
(355 |
) |
(59 |
) |
(414 |
) |
(314 |
) |
(72 |
) |
(386 |
) |
(28 |
) |
|||||||||
Total |
$ | 146 | $ | 79 | $ | 225 | $ | | $ | 23 | $ | 23 | $ | 202 | |||||||||
December 31, 2009 |
|||||||||||||||||||||||
Non-trading activities |
|||||||||||||||||||||||
Cash flow hedges |
$ | 240 | $ | 17 | $ | 257 | $ | 69 | $ | 6 | $ | 75 | $ | 182 | |||||||||
Economic hedges |
202 | 8 | 210 | 180 | | 180 | 30 | ||||||||||||||||
Trading activities |
234 | 111 | 345 | 182 | 41 | 223 | 122 | ||||||||||||||||
|
676 | 136 | 812 | 431 | 47 | 478 | 334 | ||||||||||||||||
Netting and collateral received1 |
(479 |
) |
(55 |
) |
(534 |
) |
(426 |
) |
(32 |
) |
(458 |
) |
(76 |
) |
|||||||||
Total |
$ | 197 | $ | 81 | $ | 278 | $ | 5 | $ | 15 | $ | 20 | $ | 258 | |||||||||
14
Income Statement Impact of Derivative Instruments
The following table provides the activity of accumulated other comprehensive income, containing the information about the changes in the fair value of cash flow hedges and reclassification from accumulated other comprehensive income into results of operations:
|
Cash Flow Hedge Activity1 Six Months Ended June 30, |
|
||||||
---|---|---|---|---|---|---|---|---|
|
Income Statement Location |
|||||||
(in millions) |
2010 |
2009 |
||||||
Accumulated other comprehensive income derivative gain at January 1 |
$ | 175 | $ | 398 | ||||
Effective portion of changes in fair value |
30 | 109 | ||||||
Reclassification from accumulated other comprehensive income to net income |
(122 | ) | (55 | ) | Operating revenues | |||
Accumulated other comprehensive income derivative gain at June 30 |
$ | 83 | $ | 452 | ||||
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 a net gain (loss) of $(7) million and $5 million during the second quarters of 2010 and 2009, respectively, and $1 million and $5 million during the six months ended June 30, 2010 and 2009, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues on the consolidated statements of income (loss).
The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading purposes on the consolidated statements of income (loss) is presented below:
|
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Income Statement Location |
||||||||||||||
(in millions) |
2010 |
2009 |
2010 |
2009 |
|||||||||||
Economic hedges |
Operating revenue | $ | (3 | ) | $ | 3 | $ | (7 | ) | $ | 16 | ||||
|
Fuel expense | (2 | ) | 14 | (1 | ) | 14 | ||||||||
Trading activities |
Operating revenue |
33 |
17 |
80 |
27 |
||||||||||
Contingent Features/Credit Related Exposure
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 counterparties related to the net of accounts payable, accounts receivable, unrealized losses and unrealized gains in connection with derivative activities. 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 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
15
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. 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. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at June 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. 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 EME's consolidated balance sheets. The following table summarizes margin and collateral deposits provided to and received from counterparties:
(in millions) |
June 30, 2010 |
December 31, 2009 |
||||||
---|---|---|---|---|---|---|---|---|
Collateral provided to counterparties |
||||||||
Offset against derivative liabilities |
$ | 26 | $ | 49 | ||||
Reflected in margin and collateral deposits |
108 | 120 | ||||||
Collateral received from counterparties |
||||||||
Offset against derivative assets |
55 | 124 | ||||||
Note 4. Accumulated Other Comprehensive Income
Accumulated other comprehensive income consisted of the following:
(in millions) |
Unrealized Gains on Cash Flow Hedges, Net |
Unrecognized Losses and Prior Service Adjustments, Net1 |
Accumulated Other Comprehensive Income |
||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2009 |
$ | 105 | $ | (27 | ) | $ | 78 | ||||
Current period change |
(55 | ) | | (55 | ) | ||||||
Balance at June 30, 2010 |
$ | 50 | $ | (27 | ) | $ | 23 | ||||
Included in accumulated other comprehensive income at June 30, 2010 was $60 million, net of tax, in unrealized gains on commodity-based cash flow hedges; and a $10 million, net of tax, unrealized loss related to interest rate hedges.
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
16
markets are lower than the contract prices. Approximately $67 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 revenue 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. The maximum period over which a commodity cash flow hedge is designated is through December 31, 2012.
Note 5. Discontinued Operations
Summarized financial information for discontinued operations is as follows:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
|||||||||
Income (loss) before income taxes |
$ | 4 | $ | (12 | ) | $ | 15 | $ | (6 | ) | |||
Provision (benefit) for income taxes |
1 | (5 | ) | 6 | (2 | ) | |||||||
Income (loss) from operations of discontinued foreign subsidiaries |
$ | 3 | $ | (7 | ) | $ | 9 | $ | (4 | ) | |||
During the second quarter and six months ended June 30, 2010, EME made payments of $15 million and $41 million, respectively, for a tax indemnity related to EME's previous sale of an international project. EME recorded year-to-date discontinued operations income before taxes of $15 million due primarily to expiration of a contract indemnity during the first six months of 2010 and changes in foreign exchange rates.
17
Note 6. Consolidated Statement of Changes in Equity
Consolidated statement of changes in equity at the beginning and the end of the six months ended June 30, 2009 and 2010:
|
|
EME Shareholder's Equity | |
||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Total Equity |
Common Stock |
Additional Paid-in Capital |
Retained Earnings |
Accumulated Other Comprehensive Income |
Non- controlling Interest |
|||||||||||||
Balance at December 31, 2008 |
$ | 2,764 | $ | 64 | $ | 1,335 | $ | 1,085 | $ | 200 | $ | 80 | |||||||
Net income (loss) |
95 | 96 | (1 | ) | |||||||||||||||
Other comprehensive income |
30 | 30 | |||||||||||||||||
Payments to Edison International for stock purchases related to stock-based compensation |
(1 | ) | (1 | ) | |||||||||||||||
Other stock transactions, net |
2 | 2 | |||||||||||||||||
Cash contributions from noncontrolling interests |
1 | 1 | |||||||||||||||||
Cash distributions to noncontrolling interests |
(1 | ) | (1 | ) | |||||||||||||||
Balance at June 30, 2009 |
$ |
2,890 |
$ |
64 |
$ |
1,337 |
$ |
1,180 |
$ |
230 |
$ |
79 |
|||||||
Balance at December 31, 2009 |
$ |
2,837 |
$ |
64 |
$ |
1,339 |
$ |
1,280 |
$ |
78 |
$ |
76 |
|||||||
Impact of deconsolidation of variable interest entities (Note 7) |
(71 | ) | (71 | ) | |||||||||||||||
Cumulative effect of a change in accounting principle, net of tax1 |
10 | 10 | |||||||||||||||||
Net income |
64 | 64 | |||||||||||||||||
Other comprehensive loss |
(55 | ) | (55 | ) | |||||||||||||||
Payments to Edison International for stock purchases related to stock-based compensation |
(2 | ) | (2 | ) | |||||||||||||||
Other stock transactions, net |
3 | 3 | |||||||||||||||||
Purchase of noncontrolling interests2 |
(5 | ) | (5 | ) | |||||||||||||||
Balance at June 30, 2010 |
$ |
2,781 |
$ |
64 |
$ |
1,337 |
$ |
1,352 |
$ |
23 |
$ |
5 |
|||||||
Note 7. Variable Interest Entities
Effective January 1, 2010, EME adopted the FASB's new guidance regarding variable interest entities. A variable interest entity is defined as a legal entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk lack any of the following three
18
characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The new guidance replaces the predominantly quantitative model for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity with a qualitative approach. Under this new qualitative model, the primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the variable interest entity that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met. Commercial and operating activities are generally the factors that most significantly impact the economic performance of variable interest entities in which EME has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
Projects or Entities that are Consolidated
At June 30, 2010 and December 31, 2009, EME had majority interests in 15 wind projects with a total generating capacity of 701 MW that have minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. As of December 31, 2009, all of these projects were consolidated by EME. Upon the application of the new guidance effective January 1, 2010, EME deconsolidated two of these projects. See further discussion in "Projects that are not Consolidated." In determining that EME was the primary beneficiary of the 13 projects consolidated at June 30, 2010, 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.
The following table presents summarized financial information of the wind projects that had minority interests held by others and were consolidated by EME:
(in millions) |
June 30, 2010 |
December 31, 2009 |
||||||
---|---|---|---|---|---|---|---|---|
Current assets |
$ | 26 | $ | 73 | ||||
Net property, plant and equipment1 |
682 | 944 | ||||||
Other long-term assets |
2 | 2 | ||||||
Total assets1 |
$ | 710 | $ | 1,019 | ||||
Current liabilities |
$ | 16 | $ | 17 | ||||
Long-term obligations net of current maturities |
18 | 20 | ||||||
Deferred revenues |
57 | 58 | ||||||
Other long-term liabilities |
19 | 21 | ||||||
Total liabilities |
$ | 110 | $ | 116 | ||||
Noncontrolling interests |
$ | 5 | $ | 76 | ||||
Assets serving as collateral for the debt obligations had a carrying value of $79 million and $81 million at June 30, 2010 and December 31, 2009, respectively, and primarily consist of property, plant and equipment.
EME has a 50% partnership interest in the Ambit project. EME has the power to direct the commercial and operating activities of the project pursuant to the existing contracts and has the
19
obligation to absorb losses and right to receive benefits from the project. Therefore, under the new guidance, EME is the primary beneficiary. As the primary beneficiary, EME consolidated Ambit project assets totaling $99 million on January 1, 2010.
The following table presents the summarized financial information of the Ambit project consolidated by EME:
(in millions) |
June 30, 2010 |
||||
---|---|---|---|---|---|
Current assets |
$ | 16 | |||
Net property, plant and equipment |
81 | ||||
Other long-term assets |
3 | ||||
Total assets |
$ | 100 | |||
Current liabilities |
$ | 13 | |||
Long-term obligations net of current maturities |
64 | ||||
Deferred revenues |
13 | ||||
Other long-term liabilities |
2 | ||||
Total liabilities |
$ | 92 | |||
Substantially all of the assets above are pledged as collateral for the partnership's debt obligations.
The consolidated statements of income (loss) and cash flow for the six months ended June 30, 2010 were not significantly impacted by the consolidation of the Ambit project.
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. As of June 30, 2010 and December 31, 2009, EME had five significant variable interests in projects that are not consolidated consisting of the Big 4 projects and the Sunrise project. The following table presents summarized financial information of these five significant projects:
|
Six Months Ended June 30, | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||
Revenues |
$ | 341 | $ | 311 | |||
Expenses |
(302 | ) | (273 | ) | |||
Net income |
$ | 39 | $ | 38 | |||
A subsidiary of EME operates the 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.
As noted previously in "Projects or Entities that are Consolidated," EME deconsolidated two renewable wind energy generating facilities, the Elkhorn Ridge wind project and San Juan Mesa wind project, on January 1, 2010. The primary purpose of these projects is to operate renewable wind energy facilities. The commercial and operating activities of these entities are directed by a management committee comprised of representatives of each partner. Thus, EME is not the primary beneficiary of
20
these projects. Accordingly, effective January 1, 2010, EME accounts for its interests in these projects 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:
|
As of June 30, 2010 | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
Investment |
Maximum Exposure |
|||||
Natural gas-fired projects |
$ | 325 | $ | 325 | |||
Wind projects |
174 | 174 | |||||
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 on a long-term financing of a project 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 June 30, 2010, entities which EME has accounted for under the equity method had indebtedness of $143 million, of which $54 million is proportionate to EME's ownership interest in these projects.
Note 8. Compensation and Benefit Plans
Pension Plans and Postretirement Benefits Other Than Pensions
Contributions to EME's pension plans were $4 million for the six months ended June 30, 2010 and are estimated at $18 million for the last six months of 2010.
The following are components of pension expense:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
|||||||||
Service cost |
$ | 4 | $ | 4 | $ | 8 | $ | 7 | |||||
Interest cost |
4 | 3 | 7 | 6 | |||||||||
Expected return on plan assets |
(3 | ) | (2 | ) | (5 | ) | (4 | ) | |||||
Amortization of net loss |
| 1 | 1 | 2 | |||||||||
Total expense |
$ | 5 | $ | 6 | $ | 11 | $ | 11 | |||||
Postretirement Benefits Other Than Pensions
Contributions to EME's postretirement benefits other than pensions were $1 million for the six months ended June 30, 2010 and are estimated at $1 million for the last six months of 2010.
21
The following are components of postretirement benefits expense:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
|||||||||
Service cost |
$ | | $ | | $ | 1 | $ | 1 | |||||
Interest cost |
2 | 2 | 3 | 3 | |||||||||
Amortization of prior service credit |
(1 | ) | (1 | ) | (1 | ) | (1 | ) | |||||
Amortization of net loss |
| 1 | | 1 | |||||||||
Total expense |
$ |
1 |
$ |
2 |
$ |
3 |
$ |
4 |
|||||
The table below contains a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations attributable to common shareholders:
|
Six Months Ended June 30, | ||||||
---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||
Provision for income tax at federal statutory rate of 35% |
$ | 3 | $ | 41 | |||
State taxnet of federal benefit (excludes state tax settlement) |
(2 | ) | 9 | ||||
Production tax credits |
(33 | ) | (30 | ) | |||
Federal settlement of tax disputes |
| (6 | ) | ||||
Resolution of 1986-2002 state tax issues |
(20 | ) | | ||||
Other |
5 | 3 | |||||
Income tax expense (benefit) from continuing operations |
$ |
(47 |
) |
$ |
17 |
||
EME recorded a tax benefit of $20 million in the second quarter of 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service in 2009 for the tax years 1986 through 2002.
In the second quarter of 2009, Edison International and the Internal Revenue Service completed a settlement of federal tax disputes and affirmative claims for open tax years 1986 through 2002. During the second quarter of 2009, EME recorded an income tax benefit of $6 million due to the settlement and related estimated impact of interest and state income taxes.
Note 10. Commitments and Contingencies
In March 2010, EME completed through its subsidiary, Cedro Hill Wind, LLC, a non-recourse financing of its interests in the Cedro Hill wind project. The financing included a $135 million construction loan that is required to be converted to a 15-year amortizing term loan by May 31, 2011,
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subject to meeting specified conditions, a $21 million letter of credit facility and a $4 million working capital facility.
Interest under the term loan will accrue at LIBOR plus 3% initially, with the rate increasing 0.125% after the third, sixth, ninth and eleventh years and 0.25% after the thirteenth year. Pursuant to the financing agreement, Cedro Hill Wind entered into a forward starting interest rate swap agreement at 4.29% to hedge the majority of the variable interest rate debt effective December 31, 2010, the same date EME estimates that the construction loan will convert to the term loan.
As of June 30, 2010, there was $65 million outstanding under the construction loan at a weighted average interest rate of 3.35% classified as a construction loan on EME's consolidated balance sheet and $11.5 million of outstanding letters of credit.
EME consolidated the Ambit project on January 1, 2010. At June 30, 2010, this project had $71 million of bonds payable, which are supported by a letter of credit. Principal payments are due annually through October 1, 2017. Interest rates are reset weekly based on current bond yields for similar securities. The average interest rate for the six months ended June 30, 2010 was 0.26%. Annual maturities of this debt at June 30, 2010 for the next five years are summarized as follows: $8 million in 2010, $8 million in 2011, $9 million in 2012, $10 million in 2013, and $10 million in 2014.
The Ambit project is required to maintain funded reserve accounts primarily for debt servicing and maintenance costs. The required reserve account balance at June 30, 2010 was $21 million and was under funded by $15 million. The underfunded reserve does not create an event of default under the loan, but does restrict distributions from the Ambit project.
At June 30, 2010, EME's subsidiaries had firm commitments to spend approximately $447 million during the remainder of 2010 on capital and construction expenditures. These expenditures primarily relate to the construction of wind projects. 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 has entered into various turbine supply agreements with vendors to support its wind development efforts. As of June 30, 2010, EME had commitments, excluding turbines subject to the legal dispute described below, to purchase 46 wind turbines (69 MW) and had 13 wind turbines (33 MW) in storage to be used for future wind projects. EME has 59 wind turbines (102 MW) available for future projects, excluding turbines allocated to projects in construction and turbines subject to the legal dispute. EME has payment commitments related to wind turbines of $85 million due in 2011. During the second quarter, EME deferred the delivery and $82 million in payments for 69 MW of turbines to January 2011.
Excluded from the turbine agreements referred to above is a turbine supply agreement between Mitsubishi Power Systems Americas, Inc. and EME, which is subject to a legal dispute. EME has made deposits of $68 million for the purchase of 83 wind turbines (199 MW) under this agreement. The
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remaining payments under this agreement subject to dispute are $289 million, mostly related to undelivered wind turbines. Resolution of this dispute will impact whether, and to what extent, future payments may be due under this agreement.
Fuel Supply and Transportation Contracts
At June 30, 2010, Midwest Generation and Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are estimated to aggregate $936 million, summarized as follows: $251 million for the remainder of 2010, $405 million in 2011, $247 million in 2012, and $33 million in 2013.
At June 30, 2010, Midwest Generation and Homer City each had contractual agreements for the transport of coal to their respective facilities. The commitments under these contracts are based on either actual coal purchases or minimum quantities. Accordingly, contractual obligations for transportation based on actual coal purchases are derived from committed coal volumes set forth in fuel supply contracts. The minimum commitments under these contracts are estimated to aggregate $314 million, summarized as follows: $143 million for the remainder of 2010, and $171 million in 2011.
In addition to the above, in July 2010, Midwest Generation entered into additional contracts for the purchase of coal. These commitments, together with the estimated transportation costs under the existing agreements, are estimated to be $101 million for 2011.
At June 30, 2010, letters of credit under EME's credit facility aggregated $100 million and were scheduled to expire as follows: $34 million in 2010 and $66 million in 2011. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $29 million and were scheduled to expire as follows: $2 million in 2010 and $27 million in 2011.
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 include performance guarantees, guarantees of debt 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 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 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." The sale-leaseback participants have requested similar
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indemnification. 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 2011. There were approximately 217 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2010. Midwest Generation had recorded a $49 million liability at June 30, 2010 for previous, pending and future claims.
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 Facilities
In connection with the acquisition of the Homer City facilities, 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 facilities, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. For discussion of the NOV received by Homer City and associated indemnity claims, see "ContingenciesHomer City New Source Review Notice of Violation." 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 valid claims from the sellers or purchasers, as the case may be. At June 30, 2010, EME had recorded a liability of $39 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 asset 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.
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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 facilities 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.
Midwest Generation New Source Review Lawsuit
In March 2010, the Federal District Court for the Northern District of Illinois dismissed nine of the ten counts related to PSD requirements in the complaint filed by the US EPA and the State of Illinois against Midwest Generation, holding that, as a subsequent owner, Midwest Generation could not be held liable under the PSD provisions for modifications allegedly made by Commonwealth Edison, the prior owner of the Midwest Generation plants. The Court also dismissed the tenth count to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. The decision did not address (i) 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, or (ii) the complaint in intervention filed by a group of Chicago-based environmental action groups, which also alleges opacity and particulate matter violations.
In April 2010, the US EPA formally issued to EME the same NOV that was issued to Midwest Generation in 2007. The transmittal letter stated that the action was based on a review of the asset purchase agreement for the Midwest Generation plants and that the NOV was being issued to EME as a successor in interest to Commonwealth Edison.
In June 2010, the US EPA, the State of Illinois, and several environmental groups filed amended complaints in the New Source Review litigation. The amended complaints are similar to the prior complaints, but seek to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. An August status hearing has been scheduled, at which time a schedule for responses to the amended complaints and other procedural matters will be determined.
In August 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the PSD requirements and of the New Source Performance Standards of the CAA, including alleged
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requirements to obtain a construction permit and to install controls sufficient to meet 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. At approximately the same time, Commonwealth Edison received an NOV substantially similar to the Midwest Generation NOV. Midwest Generation, Commonwealth Edison, the US EPA, and the U.S. Department of Justice, along with several Chicago-based environmental action groups, had discussions designed to explore the possibility of a settlement but no settlement resulted.
In August 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging claims substantially similar to those in the NOV. 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 those required under the CPS. By order dated January 19, 2010, the Court allowed a group of Chicago-based environmental action groups to intervene in the case.
The owner participants of the Powerton and Joliet Stations have sought indemnification and defense from Midwest Generation and/or EME for costs and liabilities associated with these matters. EME responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.
An adverse decision could involve penalties and remedial actions that would have a material adverse impact on the financial condition and results of operations of EME. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.
Homer City New Source Review Notice of Violation
In May 2010, Homer City received an NOV from the US EPA. The new NOV alleges claims similar to those in the 2008 NOV, but it adds nonattainment New Source Review requirements to the alleged PSD violations. It also adds two prior owners of the Homer City facilities as parties.
In July 2010, Homer City received a 60-day Notice of Intent to Sue signed by the State of New York and the Pennsylvania Department of Environmental Protection (PADEP), stating their intent to file a citizen suit based on the same or similar theories advanced by the US EPA in the NOV. The Notice of Intent to Sue also named the sale-leaseback owner participants of the Homer City facilities, Homer City's general partner and limited partner, and two prior owners of the Homer City facilities.
In June 2008, Homer City received an NOV from the US EPA alleging that, beginning in 1988, Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the PSD requirements of the CAA. The US EPA also alleges that Homer City has failed to file timely and
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complete Title V permits. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. On June 30, 2009 and January 2, 2010, the US EPA issued requests for information to Homer City under Section 114 of the CAA. Homer City is working on a response to the requests. Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the U.S. Department of Justice files suit, litigation could take many years to resolve the issues alleged in the NOV. EME cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.
Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the asset purchase agreement pursuant to which Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting a portion of defense costs related to the claims.
Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, sought indemnification and defense from Homer City for costs and liabilities associated with the Homer City NOV. Homer City responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.
Because EME does not own or operate any assets, other than the stock of its subsidiaries, it does not have any direct environmental obligations or liabilities. However, 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's 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. The facilities of EME's subsidiaries which are most affected by environmental regulation are located in Illinois and Pennsylvania.
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 $3 million at June 30, 2010 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 can 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 requires 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. However, based on available information, management believes that future remediation costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.
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Midwest Generation Environmental Compliance Plans and Costs
During the second quarter of 2010, Midwest Generation continued its permitting and planning activities for NOx and SO2 controls to meet the requirements of the CPS. Midwest Generation has now received all necessary permits from the Illinois EPA allowing the installation of SNCR technology on multiple units to meet the NOx portion of the CPS.
In addition, work continued on the possible employment of FGD technology using dry scrubbing with sodium-based sorbents as a method to comply with the SO2 portion of the CPS. Testing of this technology demonstrated significant reductions in SO2 emissions when using the low-sulfur coal employed by Midwest Generation. Use of this technology in combination with low-sulfur coal is expected to require substantially less capital and installation time than the spray dryer absorber technology originally contemplated, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants. Also, the use of dry scrubbing with sodium-based sorbents to meet environmental regulations will likely require Midwest Generation to incur the costs of upgrading its particulate removal systems.
Based on this work, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, at approximately $1.2 billion in 2010 dollars. If completed, these expenditures would be incurred over multiple years. Midwest Generation expects to seek permits from the Illinois EPA for select initial units later this year.
Decisions regarding whether or not to proceed with the above projects or other approaches to compliance 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 shut down units, instead of installing controls, to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation may 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.
Homer City Environmental Issues and Capital Resource Limitations
Homer City operates selective catalytic reduction equipment on all three units to reduce NOx emissions, operates FGD equipment on Unit 3 to reduce SO2 emissions, and uses coal-cleaning equipment on site to reduce the ash and sulfur content of raw coal to meet both combustion and environmental requirements. Homer City may be required to install additional environmental equipment on Unit 1 and Unit 2 to comply with environmental regulations for future operations. For further information, see "Transport Rule" and "Homer City New Source Review Notice of Violation." Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Homer City will have limited ability to obtain additional outside capital for such projects without amending its lease and related agreements. EME is under no contractual obligation to provide funding to Homer City.
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In June 2010, the US EPA finalized the PSD and Title V GHG tailoring rule. The effective date of the final rule is August 2, 2010. The emissions thresholds for CO2 equivalents in the final rule are as follows:
|
|
|
---|---|---|
January - June 2011 | 75,000 tons per year for new and modified sources already subject to PSD for pollutants other than GHGs | |
July 2011 - June 2013 |
100,000 tons per year for new sources, and 75,000 tons per year for modified sources |
|
Petitions for judicial review of the GHG tailoring rule are to be submitted by August 2, 2010. Legal challenges to the GHG tailoring rule have been filed.
In July 2010, the US EPA issued a Notice of Proposed Rulemaking for a proposed rule, known as the Transport Rule, which would require 31 eastern states (including Pennsylvania and Illinois) and the District of Columbia to substantially reduce power plant emissions of NOx and SO2 starting in 2012, with additional reductions in 2014. The Transport Rule would replace the Clean Air Interstate Rule, which had been remanded to the US EPA in 2008 for issuance of a revised rule.
The US EPA has proposed three possible approaches to emissions allowance trading. Under its preferred approach, a pollution limit would be set for each state, intrastate trading would be permitted among power plants, and limited interstate trading would also be permitted consistent with the requirement that each state meet its own pollution control obligations. Under the first alternative, a pollution limit would be set for each state, and only intrastate trading of allowances would be permitted. Under the second alternative, a pollution limit would be set for each state and an emissions limit would be set for each power plant, and limited emissions averaging would be permitted among affected units.
Under the Transport Rule, each covered state would initially be subject to a federal implementation plan designed to reduce pollution that significantly contributed to nonattainment of, or interferes with the maintenance of, NAAQS in other states. States would be able to choose to develop state implementation plans to replace the federal implementation plans.
Comments on the Transport Rule will be due 60 days after its publication in the Federal Register. The Transport Rule is scheduled to be finalized in 2011. The Clean Air Interstate Rule will remain in place until that time. EME believes that the US EPA's preferred approach to emissions allowance trading would provide allowance allocations which are adequate for the Midwest Generation plants based on projected emissions using the Illinois CPS allowable emission rates. If adopted as proposed, the Transport Rule may require the installation of additional environmental equipment to reduce SO2 emissions at Units 1 and 2 of the Homer City facilities.
National Ambient Air Quality Standard for Sulfur Dioxide
In June 2010, the US EPA finalized the primary NAAQS for SO2 by establishing a new one-hour standard at a level of 75 parts per billion. The final standard is in line with EME's expectations and is being taken into account in EME's environmental compliance strategy. Revisions to state implementation plans to achieve compliance with the new standard are due to be submitted to the US
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EPA by February 2014. The US EPA anticipates that the deadline for attainment with the SO2 NAAQS will be August 2017 (five years after the US EPA intends to finalize initial determinations as to the areas of the country that are and are not in attainment with the primary SO2 NAAQS).
Hazardous Substances and Hazardous Waste Laws
In June 2010, the US EPA published proposed regulations relating to coal combustion wastes. Two different proposed approaches are under consideration. The first approach, under which the US EPA would list these wastes as special wastes subject to regulation under Subtitle C of the Resource Conservation and Recovery Act (the section for hazardous wastes), could require EME to incur additional capital and operating costs. The second approach, under which the US EPA would regulate these wastes under Subtitle D of the Resource Conservation and Recovery Act (the section for nonhazardous wastes), is substantially similar to the requirements of existing regulations.
Note 11. Supplemental Cash Flows Information
|
Six Months Ended June 30, |
|||||||
---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
||||||
Cash paid (received) |
||||||||
Interest (net of amount capitalized1) |
$ | 142 | $ | 139 | ||||
Income taxes |
(68 | ) | 12 | |||||
Cash payments under plant operating leases |
197 | 200 | ||||||
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 | | ||||||
In July 2010, EME completed through its subsidiary, Laredo Ridge Wind, LLC, a non-recourse financing of its interests in the Laredo Ridge wind project. The financing included a $75 million construction loan that converts to a 15-year amortizing term loan subject to meeting specified conditions, a $53 million bridge loan secured by the expected U.S. Treasury grant, a $9 million letter of credit facility and a $3 million working capital facility.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This MD&A 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:
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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 32 of EME's annual report on Form 10-K for the year ended December 31, 2009. Readers are urged to read this entire quarterly report on Form 10-Q and 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, 2009, and as compared to the second quarter of 2009 and six months ended June 30, 2009. 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, 2009.
EME is a holding company whose subsidiaries and affiliates are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power
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production facilities. EME also conducts hedging and energy trading activities in power markets through its EMMT subsidiary.
This overview is presented in four sections:
The overview is presented as an update to the overview presented in EME's 2009 annual report on Form 10-K. For additional information on these topics, refer to "Management's Overview" on page 48 of EME's annual report on Form 10-K for the year ended December 31, 2009.
Highlights of Operating Results
Net income attributable to EME common shareholders is comprised of the following components:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
Change |
2010 |
2009 |
Change |
||||||||||||||
Net income (loss) attributable to EME common shareholders |
$ | (17 | ) | $ | 40 | $ | (57 | ) | $ | 64 | $ | 96 | $ | (32 | ) | |||||
Non-Core Items |
||||||||||||||||||||
Income (loss) from discontinued operations |
3 | (7 | ) | 10 | 9 | (4 | ) | 13 | ||||||||||||
Settlement of tax disputes |
20 | 6 | 14 | 20 | 6 | 14 | ||||||||||||||
Total non-core items |
23 | (1 | ) | 24 | 29 | 2 | 27 | |||||||||||||
Core Earnings |
$ | (40 | ) | $ | 41 | $ | (81 | ) | $ | 35 | $ | 94 | $ | (59 | ) | |||||
EME's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings 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 are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to EME shareholders excluding income from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings such as settlement of prior year tax liabilities, change in tax law and other activities that are no longer continuing, and non-recurring regulatory or legal proceedings.
EME's second quarter 2010 core earnings were lower than second quarter 2009 core earnings primarily due to the following:
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during 2010. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. Lower availability in 2010 compared to the same period in 2009 was also the result of deratings caused by opacity at the Homer City facilities and transmission line tornado damage impacting the Powerton Station. In addition, EME's results were impacted by $17 million of unrealized losses during the second quarter of 2010 compared to unrealized gains of $24 million during the same period last year.
These decreases were partially offset by the following:
EME's core earnings for the six months ended June 30, 2010 were lower than core earnings for the six months ended June 30, 2009 primarily due to the following:
These decreases were partially offset by the following:
Consolidated non-core items for EME included:
Midwest Generation Environmental Compliance Plans and Costs
During the second quarter of 2010, Midwest Generation continued its permitting and planning activities for NOx and SO2 controls to meet the requirements of the CPS. Midwest Generation has now received all necessary permits from the Illinois EPA allowing the installation of SNCR technology on multiple units to meet the NOx portion of the CPS.
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In addition, work continued on the possible employment of FGD technology using dry scrubbing with sodium-based sorbents as a method to comply with the SO2 portion of the CPS. Testing of this technology demonstrated significant reductions in SO2 emissions when using the low-sulfur coal employed by Midwest Generation. Use of this technology in combination with low-sulfur coal is expected to require substantially less capital and installation time than the spray dryer absorber technology originally contemplated, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants. Also, the use of dry scrubbing with sodium-based sorbents to meet environmental regulations will likely require Midwest Generation to incur the costs of upgrading its particulate removal systems.
Based on this work, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, at approximately $1.2 billion in 2010 dollars. If completed, these expenditures would be incurred over multiple years. Midwest Generation expects to seek permits from the Illinois EPA for select units later this year.
Decisions regarding whether or not to proceed with the above projects or other approaches to compliance 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 shut down units, instead of installing controls, to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation may 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 June 2010, the US EPA published its final GHG tailoring rule, with less stringent statutory emissions thresholds for GHGs than those originally proposed in late 2009. Since the rule affects only new or modified sources, it is not expected to have any immediate effect on the fossil-fuel generating stations of Midwest Generation or Homer City.
In June 2010, the US EPA finalized the primary NAAQS for SO2 by establishing a new one-hour standard at a level of 75 parts per billion. The final standard is in line with EME's expectations and is being taken into account in EME's environmental compliance strategy.
In June and July of 2010, two proposed rules were published. The first proposed rule, known as the Transport Rule (a replacement for the Clean Air Interstate Rule), would substantially reduce power plant emissions of NOx and SO2 starting in 2012, with additional reductions in 2014, and would impose new limitations on emissions allowance trading. The second proposal relates to the handling of coal combustion wastes.
For further discussion, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Commitments and ContingenciesContingenciesEnvironmental Developments."
36
EME has four projects totaling 600 MW under construction. Included among the projects under construction is the 130 MW Taloga project, which is slated to utilize wind turbines that are subject to a legal dispute. EME also had a development pipeline of potential wind projects with projected installed capacity of approximately 3,400 MW at June 30, 2010. EME had a purchase contract for 69 MW of wind turbines, and 33 MW of wind turbines in storage, that are to be used for projects not yet under construction as of June 30, 2010, excluding turbine purchase contracts for 199 MW of wind turbines that are subject to a legal dispute. EME has deferred delivery and payment for the 69 MW of turbines under the purchase contract to January 2011. If EME is unable to develop such projects on acceptable terms and conditions, certain turbine orders may be terminated, which would result in a material charge. The pace of additional growth in EME's renewables program will be subject to the availability of projects that meet EME's requirements and the capital needed for development, which will be affected by the extent of internally generated cash flow and future decisions about capital expenditures for environmental compliance by its coal fleet. Consequently, pending substantial progress on or financing of the environmental retrofits, growth of the renewables program may depend upon the availability of third-party financing.
EME filed a complaint in the Superior Court of the State of California against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. Matters under dispute include, among other things, the requirement to purchase and pay the remaining purchase price for 199 MW of wind turbines, including related services and warranties, among other items, in the approximate amount of $289 million. The complaint asks the Court for, among other things, an order finding the supply agreement void and unenforceable and for an award of monetary damages, including return to EME of deposits of $68 million previously made for the units subject to dispute. See "Legal Proceedings" in Part II of this quarterly report.
At June 30, 2010, EME had cash and cash equivalents and short-term investments of $333 million to meet liquidity needs as well as $464 million of capacity under its credit facility.
Capital expenditures to complete renewable related projects through 2011 are projected to be $495 million (excluding disputed turbine amounts of approximately $289 million) at June 30, 2010. In addition to available lines of credit and cash and cash equivalents, the following table summarizes the projected sources of cash to fund EME's anticipated expenditures:
(in millions) |
|
||||
---|---|---|---|---|---|
Secured project financings: |
|||||
Big Sky1 |
$ | 200 | |||
Cedro Hill1 |
70 | ||||
Anticipated U.S. Treasury grants2 |
377 | ||||
|
$ | 647 | |||
37
Results of Continuing Operations
EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of energy and capacity from the fossil-fueled facilities. Equity in income from unconsolidated affiliates primarily relates to energy projects accounted for under the equity method. EME recognizes its proportional share of the income or loss of such entities.
The following section and table provide a summary of results of EME's operating projects and corporate expenses for the second quarters of 2010 and 2009 and six months ended June 30, 2010 and 2009, 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 (AOI) of EME's projects:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
|||||||||
Midwest Generation plants |
$ | (39 | ) | $ | 74 | $ | 48 | $ | 188 | ||||
Homer City facilities |
| 47 | 37 | 83 | |||||||||
Renewable energy projects |
19 | 11 | 29 | 37 | |||||||||
Energy trading |
31 | 17 | 78 | 27 | |||||||||
Big 4 projects |
12 | 11 | 16 | 17 | |||||||||
Sunrise |
7 | 6 | 3 | 1 | |||||||||
Doga |
| 8 | 15 | 8 | |||||||||
March Point |
| 1 | 17 | 3 | |||||||||
Westside projects |
| | 1 | 3 | |||||||||
Other projects |
3 | 3 | 6 | 5 | |||||||||
Other operating income (expense) |
(1 | ) | | 1 | | ||||||||
|
32 | 178 | 251 | 372 | |||||||||
Corporate administrative and general |
(34 | ) | (43 | ) | (70 | ) | (79 | ) | |||||
Corporate depreciation and amortization |
(4 | ) | (3 | ) | (8 | ) | (6 | ) | |||||
AOI1 |
$ | (6 | ) | $ | 132 | $ | 173 | $ | 287 | ||||
38
The following table reconciles AOI to operating income (loss) as reflected on EME's consolidated statements of income (loss):
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
||||||||||
AOI |
$ | (6 | ) | $ | 132 | $ | 173 | $ | 287 | |||||
Less: |
||||||||||||||
Equity in earnings of unconsolidated affiliates |
20 | 21 | 39 | 28 | ||||||||||
Dividend income from projects |
1 | 9 | 17 | 10 | ||||||||||
Production tax credits |
19 | 14 | 33 | 30 | ||||||||||
Operating Income (Loss) |
$ | (46 | ) | $ | 88 | $ | 84 | $ | 219 | |||||
39
Adjusted Operating Income from Consolidated Operations
The following table presents additional data for the Midwest Generation plants:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
|||||||||||
Operating Revenues |
$ | 281 | $ | 340 | $ | 660 | $ | 724 | |||||||
Operating Expenses |
|||||||||||||||
Fuel1 |
98 | 110 | 239 | 233 | |||||||||||
Plant operations |
169 | 106 | 268 | 202 | |||||||||||
Plant operating leases |
18 | 19 | 37 | 38 | |||||||||||
Depreciation and amortization |
28 | 27 | 56 | 54 | |||||||||||
Administrative and general |
7 | 5 | 12 | 10 | |||||||||||
Total operating expenses |
320 | 267 | 612 | 537 | |||||||||||
Operating Income (Loss) |
(39 | ) | 73 | 48 | 187 | ||||||||||
Other Income |
| 1 | | 1 | |||||||||||
AOI |
$ | (39 | ) | $ | 74 | $ | 48 | $ | 188 | ||||||
Statistics2 |
|||||||||||||||
Generation (in GWh): |
|||||||||||||||
Energy only contracts |
5,430 | 6,361 | 13,642 | 12,117 | |||||||||||
Load requirements services contract |
| 447 | | 1,333 | |||||||||||
Total |
5,430 | 6,808 | 13,642 | 13,450 | |||||||||||
Aggregate plant performance: |
|||||||||||||||
Equivalent availability |
59.8% | 78.5% | 72.7% | 80.6% | |||||||||||
Capacity factor |
45.5% | 57.1% | 57.5% | 56.7% | |||||||||||
Load factor |
76.2% | 72.7% | 79.1% | 70.3% | |||||||||||
Forced outage rate |
10.4% | 5.7% | 8.2% | 6.4% | |||||||||||
Average realized price/MWh: |
|||||||||||||||
Energy only contracts |
$ | 41.50 | $ | 41.38 | $ | 40.31 | $ | 44.41 | |||||||
Load requirements services contract |
$ | | $ | 62.47 | $ | | $ | 62.52 | |||||||
Capacity revenue only (in millions) |
$ | 58 | $ | 42 | $ | 105 | $ | 81 | |||||||
Average realized fuel costs/MWh |
$ | 17.55 | $ | 18.19 | $ | 16.99 | $ | 18.37 | |||||||
AOI from the Midwest Generation plants decreased $113 million and $140 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of
40
2009. The 2010 decreases in AOI were primarily attributable to an increase in plant operations costs related to scheduled plant outages, unrealized losses related to hedge contracts and a decline in realized gross margin. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. The decline in realized gross margin during the second quarter was driven by lower generation, partially offset by higher capacity revenues. The year-to-date decline in realized gross margin was driven by lower average realized energy prices, partially offset by higher capacity revenues. Lower availability in 2010 compared to the same period in 2009 was also the result of deratings caused by transmission line tornado damage impacting the Powerton Station.
Included in operating revenues were unrealized gains (losses) of $(3) million and $5 million for the second quarters of 2010 and 2009, respectively, and $4 million and $20 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 were due to both the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges, and hedge contracts which are not accounted for as cash flow hedges (referred to as economic hedges). Unrealized gains in 2009 were primarily due to economic hedge contracts that are accounted for on a mark-to-market basis.
Included in fuel expenses were unrealized gains (losses) of $(2) million and $14 million for the second quarters of 2010 and 2009, respectively, and $(7) million and $14 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) were due to oil futures contracts which were accounted for as economic hedges. The contracts hedge a portion of a fuel adjustment mechanism of a rail transportation contract.
For more information regarding forward market prices and unrealized gains (losses), see "Market Risk ExposuresCommodity Price Risk" and "Results of OperationsDerivative Instruments," respectively.
41
The following table presents additional data for the Homer City facilities:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
||||||||||
Operating Revenues |
$ | 129 | $ | 161 | $ | 304 | $ | 326 | ||||||
Operating Expenses |
||||||||||||||
Fuel1 |
57 | 63 | 127 | 127 | ||||||||||
Plant operations |
39 | 22 | 76 | 56 | ||||||||||
Plant operating leases |
27 | 25 | 52 | 50 | ||||||||||
Depreciation and amortization |
4 | 3 | 9 | 8 | ||||||||||
Administrative and general |
2 | 1 | 3 | 2 | ||||||||||
Total operating expenses |
129 | 114 | 267 | 243 | ||||||||||
Operating Income |
| 47 | 37 | 83 | ||||||||||
AOI |
$ | | $ | 47 | $ | 37 | $ | 83 | ||||||
Statistics2 |
||||||||||||||
Generation (in GWh) |
2,289 | 3,025 | 5,243 | 5,683 | ||||||||||
Equivalent availability |
64.5% | 90.5% | 72.3% | 83.7% | ||||||||||
Capacity factor |
55.5% | 73.4% | 63.9% | 69.3% | ||||||||||
Load factor |
86.0% | 81.1% | 88.4% | 82.8% | ||||||||||
Forced outage rate |
14.1% | 7.0% | 12.1% | 9.5% | ||||||||||
Average realized energy price/MWh |
$ | 48.78 | $ | 46.24 | $ | 49.57 | $ | 51.29 | ||||||
Capacity revenue only (in millions) |
$ | 29 | $ | 18 | $ | 58 | $ | 30 | ||||||
Average fuel costs/MWh |
$ | 25.08 | $ | 20.91 | $ | 24.23 | $ | 22.36 | ||||||
AOI from the Homer City facilities decreased $47 million and $46 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 decreases in AOI were primarily attributable to an increase in plant operations costs related to scheduled plant outages, higher unrealized losses related to hedge contracts and a decline in realized gross margin. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. The decline in realized gross margin was driven by lower generation and higher coal costs, partially offset by higher capacity revenues. The Homer City facilities experienced increased forced outages in 2010 compared to 2009 due to opacity-related deratings.
Included in operating revenues were unrealized gains (losses) from hedge activities of $(12) million and $5 million for the second quarters of 2010 and 2009, respectively, and $(14) million and $5 million for
42
the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 and 2009 were primarily attributable to 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 the PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). For more information regarding forward market prices and unrealized gains (losses), see "Market Risk ExposuresCommodity Price Risk" and "Results of OperationsDerivative Instruments."
Non-GAAP DisclosuresFossil-Fueled Facilities
AOI is equal to operating income (loss) plus other income (expense) for the fossil-fueled facilities. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of other income (expense) is meaningful for investors as the components of other income (expense) are integral to the operating results of the fossil-fueled facilities.
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 revenue less unrealized gains (losses) and other non-energy related revenue by (ii) generation as shown in the table below. Revenue related to capacity sales is excluded from the calculation of average realized energy price.
Midwest Generation Plants |
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
||||||||||
Operating revenues |
$ | 281 | $ | 340 | $ | 660 | $ | 724 | ||||||
Less: |
||||||||||||||
Load requirements services contract |
| (28 | ) | | (83 | ) | ||||||||
Unrealized (gains) losses |
3 | (5 | ) | (4 | ) | (20 | ) | |||||||
Capacity and other revenues |
(58 | ) | (44 | ) | (106 | ) | (83 | ) | ||||||
Realized revenues |
$ | 226 | $ | 263 | $ | 550 | $ | 538 | ||||||
Generationenergy only contracts (in GWh) |
5,430 | 6,361 | 13,642 | 12,117 | ||||||||||
Average realized energy price/MWh |
$ | 41.50 | $ | 41.38 | $ | 40.31 | $ | 44.41 | ||||||
Homer City Facilities |
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
||||||||||
Operating revenues |
$ | 129 | $ | 161 | $ | 304 | $ | 326 | ||||||
Less: |
||||||||||||||
Unrealized (gains) losses |
12 | (5 | ) | 14 | (5 | ) | ||||||||
Capacity and other revenues |
(29 | ) | (17 | ) | (58 | ) | (30 | ) | ||||||
Realized revenues |
$ | 112 | $ | 139 | $ | 260 | $ | 291 | ||||||
Generation (in GWh) |
2,289 | 3,025 | 5,243 | 5,683 | ||||||||||
Average realized energy price/MWh |
$ | 48.78 | $ | 46.24 | $ | 49.57 | $ | 51.29 | ||||||
43
The average realized energy price is presented as an aid in understanding the operating results of the fossil-fueled facilities. 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 real-time market prices. A reconciliation of the operating revenues of the fossil-fueled facilities to consolidated operating revenues presented in the preceding tables is set forth below:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
||||||||||
Operating revenues |
||||||||||||||
Midwest Generation plants |
$ | 281 | $ | 340 | $ | 660 | $ | 724 | ||||||
Homer City facilities |
129 | 161 | 304 | 326 | ||||||||||
Renewable energy projects |
34 | 31 | 64 | 75 | ||||||||||
Other revenues |
49 | 25 | 116 | 44 | ||||||||||
Consolidated operating revenues as reported |
$ | 493 | $ | 557 | $ | 1,144 | $ | 1,169 | ||||||
The average realized fuel costs reflect the average cost per MWh at which fuel is consumed for generation sold into the market, including the effects of hedges. It is determined by dividing (i) fuel expense adjusted for unrealized gains (losses) by (ii) generation as shown in the table below:
Midwest Generation Plants |
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
||||||||||
Fuel expenses |
$ | 98 | $ | 110 | $ | 239 | $ | 233 | ||||||
Add back: |
||||||||||||||
Unrealized gains (losses) |
(2 | ) | 14 | (7 | ) | 14 | ||||||||
Realized fuel expenses |
$ | 96 | $ | 124 | $ | 232 | $ | 247 | ||||||
Total generation (in GWh) |
5,430 | 6,808 | 13,642 | 13,450 | ||||||||||
Average realized fuel costs/MWh |
$ | 17.55 | $ | 18.19 | $ | 16.99 | $ | 18.37 | ||||||
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 expenses. 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
44
reconciliation of the Midwest Generation plants fuel expense to consolidated fuel expense presented in the preceding table is set forth below:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
||||||||||
Fuel expense |
||||||||||||||
Midwest Generation plants |
$ | 98 | $ | 110 | $ | 239 | $ | 233 | ||||||
Homer City facilities |
57 | 63 | 127 | 127 | ||||||||||
Other |
6 | (1 | ) | 8 | (1 | ) | ||||||||
Consolidated fuel expense as reported |
$ | 161 | $ | 172 | $ | 374 | $ | 359 | ||||||
Seasonal DisclosureFossil-Fueled Facilities
Due to fluctuations in electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the fossil-fueled facilities normally vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall), further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, AOI from the fossil-fueled facilities is seasonal and has significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. For further discussion regarding market prices, see "Market Risk ExposuresCommodity Price RiskEnergy Price Risk Affecting Sales from the Fossil-Fueled Facilities."
45
The following table presents additional data for EME's renewable energy projects:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
|||||||||||
Operating Revenues |
$ | 34 | $ | 31 | $ | 64 | $ | 75 | |||||||
Production Tax Credits |
19 | 14 | 33 | 30 | |||||||||||
|
53 | 45 | 97 | 105 | |||||||||||
Operating Expenses |
|||||||||||||||
Plant operations |
12 | 12 | 24 | 25 | |||||||||||
Depreciation and amortization |
22 | 21 | 43 | 41 | |||||||||||
Administrative and general |
| 1 | 1 | 2 | |||||||||||
Total operating expenses |
34 | 34 | 68 | 68 | |||||||||||
AOI1 |
$ | 19 | $ | 11 | $ | 29 | $ | 37 | |||||||
Statistics2 |
|||||||||||||||
Generation (in GWh)3 |
992 | 718 | 1,835 | 1,538 | |||||||||||
Aggregate plant performance3: |
|||||||||||||||
Equivalent availability |
90.9% | 87.3% | 90.8% | 84.2% | |||||||||||
Capacity factor |
38.5% | 30.5% | 35.8% | 33.4% | |||||||||||
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
||||||||||
AOI |
$ | 19 | $ | 11 | $ | 29 | $ | 37 | ||||||
Less: |
||||||||||||||
Production tax credits |
19 | 14 | 33 | 30 | ||||||||||
Operating Income (Loss) |
$ | | $ | (3 | ) | $ | (4 | ) | $ | 7 | ||||
AOI from renewable energy projects increased $8 million and decreased $8 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The second quarter increase in AOI was primarily attributable to higher generation resulting from an increase in projects in operations. The year-to-date decrease in AOI results from higher
46
depreciation and operations costs related to additional projects in operations, offset by the impact of the deconsolidation of two renewable projects in 2010. AOI in the second quarter and six months ended June 30, 2009 included $5 million and $16 million, respectively, of liquidated damages from availability guarantees provided by a wind turbine supplier, which compensated EME for lower generation (none recorded in 2010). The second quarter ended June 30, 2010 did not include liquidated damages for equipment warranty related items given completion of the blade remediation program. During the second quarter of 2010, EME received $92 million in U.S. Treasury grants, which was recorded as deferred revenue and is recognized as revenue over the life of the project.
EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, coal, and transmission congestion primarily in the eastern U.S. power grid using products available over the counter, through exchanges, and from independent system operators.
AOI from energy trading activities increased $14 million and $51 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increases in AOI from energy trading activities were attributable to increased revenue in congestion and basis trading.
Adjusted Operating Income from Unconsolidated Affiliates
AOI from the Doga project decreased $8 million and increased $7 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009 due to the timing of distributions. AOI is recognized when cash is distributed from the project since the Doga project is accounted for on the cost method.
AOI from the March Point project increased $14 million for the six months ended June 30, 2010, compared to the corresponding period of 2009. The 2010 increase was primarily due to an $18 million equity distribution received from the project in February 2010. EME subsequently sold its ownership interest in the March Point project to its partner at book value.
EME's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.
47
Interest Related Income (Expense)
|
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
|||||||||||
Interest income |
$ | 1 | $ | 3 | $ | 2 | $ | 6 | |||||||
Interest expense: |
|||||||||||||||
EME debt |
$ | (58 | ) | $ | (68 | ) | $ | (118 | ) | $ | (136 | ) | |||
Non-recourse debt: |
|||||||||||||||
Midwest Generation |
| (2 | ) | (1 | ) | (5 | ) | ||||||||
EME CP Holding Co. |
(1 | ) | (1 | ) | (2 | ) | (2 | ) | |||||||
Viento Funding II, Inc. |
(4 | ) | | (8 | ) | | |||||||||
Other projects |
(3 | ) | (2 | ) | (5 | ) | (4 | ) | |||||||
|
$ | (66 | ) | $ | (73 | ) | $ | (134 | ) | $ | (147 | ) | |||
The 2010 decrease in interest expense was primarily due to higher capitalized interest and lower debt balances under EME's and Midwest Generation's credit facilities. Capitalized interest for projects under construction increased $8 million and $13 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009.
EME's income taxes from continuing operations during the second quarter of 2010 included a $20 million income tax benefit resulting from the California Franchise Tax Board's acceptance and application of the federal settlement of tax disputes finalized with the Internal Revenue Service in 2009 for tax years 1986 through 2002. In addition, income taxes for the six months ended June 30, 2010 and 2009, included tax benefits of production tax credits of $33 million and $30 million, respectively.
Results of Discontinued Operations
Income from discontinued operations, net of tax, increased $10 million and $13 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increase was due to lower foreign exchange rates. The year-to-date increase was due to a reduction in EME's estimated liability due primarily to expiration of a contract indemnity during the first quarter of 2010. EME increased its estimated liability for a tax indemnity by $6 million in the second quarter and six months ended June 30, 2009.
For a discussion of new accounting guidance affecting EME, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 1. Summary of Significant Accounting PoliciesNew Accounting Guidance."
EME classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that qualify for hedge accounting) as part of operating revenues or fuel expenses. The
48
results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities:
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
2010 |
2009 |
||||||||||
Midwest Generation plants |
||||||||||||||
Non-qualifying hedges |
$ | (4 | ) | $ | 18 | $ | (6 | ) | $ | 34 | ||||
Ineffective portion of cash flow hedges |
(1 | ) | 1 | 3 | | |||||||||
Homer City facilities |
||||||||||||||
Non-qualifying hedges |
| 1 | | | ||||||||||
Ineffective portion of cash flow hedges |
(12 | ) | 4 | (14 | ) | 5 | ||||||||
Total unrealized gains (losses) |
$ | (17 | ) | $ | 24 | $ | (17 | ) | $ | 39 | ||||
At June 30, 2010, cumulative unrealized gains of $25 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($16 million for the remainder of 2010, $8 million for 2011, and $1 million for 2012).
In determining the fair value of EME's derivative positions, EME uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EME's derivative instruments, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 2. Fair Value Measurements" and "Note 3. Derivative Instruments and Risk Management," respectively, and refer to "Fair Value of Derivative Instruments" in Item 7 on page 69 of EME's annual report on Form 10-K for the year ended December 31, 2009.
49
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 2010, EME and its subsidiaries had consolidated cash and cash equivalents of $707 million and a total of $961 million of available borrowing capacity under their credit facilities. EME's consolidated debt at June 30, 2010 was $4.1 billion, of which $107 million was current. In addition, EME's subsidiaries had $3.0 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 25 years.
The following table summarizes the status of the EME and Midwest Generation credit facilities at June 30, 2010:
(in millions) |
EME |
Midwest Generation |
|||||
---|---|---|---|---|---|---|---|
Commitment |
$ | 600 | $ | 500 | |||
Less: Commitment from Lehman Brothers subsidiary |
(36 | ) | | ||||
|
564 | 500 | |||||
Outstanding borrowings |
| | |||||
Outstanding letters of credit |
(100 | ) | (3 | ) | |||
Amount available |
$ | 464 | $ | 497 | |||
As a result of credit ratings actions in 2010, the margins applicable to Midwest Generation's $500 million working capital facility increased 27.5 basis points. Borrowings made under this credit facility currently bear interest at LIBOR plus 1.15%, unless average utilized commitments during a period exceed $250 million, in which case the margin increases to 1.275%.
For the remainder of 2010, EME anticipates capital expenditures of $635 million (excluding a $289 million disputed amount under a turbine supply agreement) to be funded with a combination of project-level financing, U.S. Treasury grants, cash on hand, and cash flow from operations. EME secured a $206 million vendor financing, of which $200 million was available at June 30, 2010, and a $160 million project financing, of which $70 million was available at June 30, 2010. EME intends to file for U.S. Treasury grants for its renewable energy projects in construction.
EME may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
50
At June 30, 2010, forecasted capital expenditures through 2012 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:
(in millions) |
July through December 2010 |
2011 |
2012 |
||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Midwest Generation Plants |
$ | 26 | $ | 79 | $ | 10 | |||||
Environmental expenditures1 |
93 | 145 | 78 | ||||||||
Homer City Facilities |
8 |
52 |
24 |
||||||||
Environmental expenditures2 |
1 | 3 | 22 | ||||||||
Renewable Projects |
495 |
|
|
||||||||
Turbine commitments4 |
| 85 | | ||||||||
Other capital expenditures |
12 |
17 |
9 |
||||||||
Total |
$ | 635 | $ | 381 | $ | 143 | |||||
Estimated Expenditures for Existing Projects
Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, mill steam inerting projects, generator stator rewinds, 4Kv switchgear and main power transformer replacement.
Environmental expenditures at Homer City relate to emission monitoring and control projects. Midwest Generation is subject to various commitments with respect to environmental compliance. Expenditures, in addition to those included on the preceding table, are anticipated and could be material; however, the amounts and timing have not been determined. For more information on the current status of
51
environmental improvements in Illinois, see "Management's OverviewEnvironmental Developments." For further discussion of environmental regulations, refer to "Environmental Matters and Regulations" in Item 1 on page 20 of EME's annual report on Form 10-K for the year ended December 31, 2009.
Estimated Expenditures for Future Projects
EME has wind turbines in storage and on order for wind projects under construction and to be used for future wind projects (turbine commitments are reflected separately in the preceding capital expenditure table). Amounts exclude balance of project costs for 102 MW available for new projects, which EME estimates to be an additional $75 million to $120 million based on typical project costs. The pace of additional growth in EME's renewables program will be subject to the availability of projects that meet EME's requirements and the capital needed for development, which will be affected by the extent of internally generated cash flow and future decisions about capital expenditures for environmental compliance by its coal fleet. Consequently, pending substantial progress on or financing of the environmental retrofits, growth of the renewables programs may depend upon the availability of outside project-level debt and equity financing. Successful completion of the development of a wind project depends upon obtaining permits and agreements necessary to support an investment and may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment.
EME's Historical Consolidated Cash Flow
This section discusses EME's consolidated cash flows from operating, financing and investing activities.
Condensed Consolidated Statement of Cash Flows
|
Six Months Ended June 30, |
||||||
---|---|---|---|---|---|---|---|
(in millions) |
2010 |
2009 |
|||||
Operating cash flow from continuing operations |
$ | 159 | $ | (91 | ) | ||
Operating cash flow from discontinued operations |
9 | (4 | ) | ||||
Net cash provided by (used in) operating activities |
168 | (95 | ) | ||||
Net cash provided by financing activities |
37 | 132 | |||||
Net cash used in investing activities |
(294 | ) | (188 | ) | |||
Net decrease in cash and cash equivalents |
$ | (89 | ) | $ | (151 | ) | |
Consolidated Cash Flows from Operating Activities
Cash provided by operating activities from continuing operations increased $250 million in the first six months of 2010, compared to the first six months of 2009. The 2010 increase was primarily attributable to a decrease in cash collateral deposits for risk management and energy trading compared to 2009, $92 million received related to U.S. Treasury grants, and changes in the timing of cash receipts and disbursements related to working capital items.
Consolidated Cash Flows from Financing Activities
Cash provided by financing activities from continuing operations decreased $95 million in the first six months of 2010, compared to the first six months of 2009. The 2010 decrease was primarily attributable
52
to lower levels of renewable energy project financing. For further project financing details, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Commitments and ContingenciesContractual ObligationsProject Financing."
Consolidated Cash Flows from Investing Activities
Cash used in investing activities from continuing operations increased $106 million in the first six months of 2010, compared to the first six months of 2009. The 2010 increase was primarily due to higher expenditures for construction of renewable energy projects compared to 2009.
On June 29, 2010, Moody's lowered the credit ratings of EME to B3 from B2 and Midwest Generation to Ba2 from Ba1. EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.
EME does not have any "rating triggers" contained in subsidiary financings that would result in it being required to make equity contributions or provide additional financial support to its subsidiaries, including EMMT. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. For discussions of contingent features related to energy contracts, see "Margin, Collateral Deposits and Other Credit Support for Energy Contracts."
For a discussion of the effect of EMMT's credit rating on EME's ability to sell forward the output of the Homer City facilities through EMMT, refer to "Credit Rating of EMMT" in Item 7 on page 78 of EME's annual report on Form 10-K for the year ended December 31, 2009.
Margin, Collateral Deposits and Other Credit Support for Energy Contracts
Future cash collateral requirements may be higher than the margin and collateral requirements were at June 30, 2010, if wholesale energy prices change or if EMMT enters into additional transactions. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding as of June 30, 2010 could increase by approximately $184 million over the remaining life of the contracts using a 95% confidence level. This increase may not be offset by similar changes in the cash flows of the underlying hedged items in the same periods. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "EME's Liquidity as a Holding Company" and "Dividend Restrictions in Major Financings."
Hedge contracts include provisions relating to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. EMMT has hedge contracts that do
53
not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at June 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or additional collateral postings under the contingent features described above.
Midwest Generation has cash on hand and a credit facility to support margin requirements specifically related to contracts entered into by EMMT related to the Midwest Generation plants. In addition, EME has cash on hand and a credit facility to provide credit support to subsidiaries. For discussion on available borrowing capacity under Midwest Generation and EME credit facilities, see "Available Liquidity." Also, for further discussion, see "EME's Liquidity as a Holding Company."
EME's Liquidity as a Holding Company
At June 30, 2010, EME had cash and cash equivalents and short-term investments of $333 million to meet liquidity needs as well as $464 million of capacity under its credit facility. EME's cash and cash equivalents included $188 million held directly by EME, as well as cash and cash equivalents related to EMMT of $143 million (which can be loaned or distributed to EME, subject to applicable corporate and other laws). Because EME, as a holding company, does not directly own any revenue-producing generation facilities, EME relies on cash distributions and tax payments from its projects to pay debt service, tax payments, contractual obligations and general and administrative expenses. Distributions to EME from projects are generally only available after all current debt service obligations at the project level have been paid and are further restricted by contractual restrictions on distributions included in the documentation evidencing the project-level debt obligations. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. For further discussion, see "Dividend Restrictions in Major Financings."
EME's Credit Facility Financial Ratios
EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility. The following details of EME's interest coverage ratio and a maximum corporate-debt-to-capital ratio are provided as an aid to understanding the components of the computations as defined in the credit facility. This information is not intended to measure the financial performance of EME and, accordingly, should not be used in lieu of the financial information set forth in EME's consolidated financial statements.
54
The following table sets forth the major components of the interest coverage ratio:
|
12 Months Ended | ||||||||
---|---|---|---|---|---|---|---|---|---|
(in millions) |
June 30, 2010 |
December 31, 2009 |
|||||||
Funds Flow Available for Interest |
|||||||||
Midwest Generation |
$ | 95 | $ | 200 | |||||
Homer City |
97 | 75 | |||||||
Big 4 Projects |
71 | 62 | |||||||
Viento Funding II, Inc.1 |
4 | 167 | |||||||
U.S. Treasury grants |
92 | | |||||||
Renewables |
84 | 41 | |||||||
Other projects |
75 | 47 | |||||||
Tax payments received from subsidiaries |
57 | 68 | |||||||
Realized trading income |
86 | 36 | |||||||
Tax allocation receipts (payments) |
196 | 139 | |||||||
Operating expenses |
(149 | ) | (151 | ) | |||||
Other items, net |
(47 | ) | (14 | ) | |||||
|
$ | 661 | $ | 670 | |||||
Net Interest Expense |
$ | 243 | $ | 261 | |||||
Addback: Capitalized interest |
32 | 19 | |||||||
Powerton-Joliet intercompany notes |
112 | 112 | |||||||
EME interest income |
(1 | ) | (2 | ) | |||||
|
$ | 386 | $ | 390 | |||||
Ratio |
1.72 | 1.72 | |||||||
Covenant threshold (not less than) |
1.20 | 1.20 | |||||||
55
Corporate-Debt-to-Capital Ratio
The following table sets forth the major components of the corporate-debt-to-capital ratio:
(in millions) |
June 30, 2010 |
December 31, 2009 |
|||||||
---|---|---|---|---|---|---|---|---|---|
Corporate Debt |
|||||||||
Indebtedness for money borrowed |
$ | 3,700 | $ | 3,700 | |||||
Powerton-Joliet termination value |
987 | 1,046 | |||||||
Letters of credit |
103 | 104 | |||||||
|
$ | 4,790 | $ | 4,850 | |||||
Corporate Capital |
|||||||||
Common shareholder's equity |
$ | 2,776 | $ | 2,761 | |||||
Less: |
|||||||||
Non-cash cumulative changes in accounting |
(9 | ) | 1 | ||||||
Accumulated other comprehensive income |
(23 | ) | (78 | ) | |||||
Adjustments: |
|||||||||
After-tax losses incurred on termination of Collins lease |
587 | 587 | |||||||
Dividend to Mission Energy Holding Company for repayment of 13.5% notes |
899 | 899 | |||||||
|
4,230 | 4,170 | |||||||
Corporate debt |
4,790 | 4,850 | |||||||
|
$ | 9,020 | $ | 9,020 | |||||
Corporate-debt-to-capital ratio |
0.53 | 0.54 | |||||||
Covenant threshold (not more than) |
0.75 | 0.75 | |||||||
Dividend Restrictions in Major Financings
Key Ratios of EME's Principal Subsidiaries Affecting Dividends
Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at June 30, 2010 or for the 12 months ended June 30, 2010:
Subsidiary |
Financial Ratio |
Covenant |
Actual |
|||
---|---|---|---|---|---|---|
Midwest Generation (Midwest Generation plants) |
Debt to Capitalization Ratio |
Less than or equal to 0.60 to 1 |
0.16 to 1 |
|||
Homer City (Homer City facilities) |
Senior Rent Service Coverage Ratio |
Greater than 1.7 to 1 |
2.53 to 1 |
|||
For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Dividend Restrictions in Major Financings" in Item 7 on page 82 of EME's annual report on Form 10-K for the year ended December 31, 2009.
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EME's Senior Notes and Guaranty of Powerton-Joliet Leases
EME is restricted under applicable agreements from the sale or disposition of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At June 30, 2010, the maximum permissible sale or disposition of EME assets is determined as follows:
(in millions) |
|
|||||
---|---|---|---|---|---|---|
Consolidated Net Tangible Assets |
||||||
Total consolidated assets |
$ | 8,641 | ||||
Less: |
||||||
Consolidated current liabilities |
495 | |||||
Intangible assets |
96 | |||||
|
$ | 8,050 | ||||
10% Threshold |
$ | 805 | ||||
This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above, are retained by EME as cash or cash equivalents or are used by EME to repay senior debt of EME or debt of its subsidiaries.
As a wholly owned indirect subsidiary of Edison International, EME is subject to determinations made by its directors, each of whom is appointed by Edison International, to act in the interests of Edison International and its shareholders, which may result in EME making distributions of cash or assets, subject to the limitations described above and applicable law, at any time or from time to time, which may affect assets held or under development.
Contractual Obligations and Contingencies
Fuel Supply and Transportation Contracts
For a discussion of fuel supply contracts and coal transportation agreements, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Commitments and ContingenciesCommitmentsFuel Supply and Transportation Contracts."
Midwest Generation New Source Review Lawsuit
For a discussion of the Midwest Generation New Source Review Lawsuit, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Commitments and ContingenciesContingenciesMidwest Generation New Source Review Lawsuit."
Homer City New Source Review Notice of Violation
For a discussion of the Homer City New Source Review Notice of Violation, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Commitments and ContingenciesContingenciesHomer City New Source Review Notice of Violation."
57
Off-Balance Sheet Transactions
For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" in Item 7 on page 86 of EME's annual report on Form 10-K for the year ended December 31, 2009. There have been no significant developments with respect to EME's off-balance sheet transactions that affect disclosures presented in EME's annual report.
Environmental Matters and Regulations
For a discussion of EME's environmental matters, refer to "Environmental Matters and Regulations" in Item 1 on page 20 of EME's annual report on Form 10-K for the year ended December 31, 2009. There have been no significant developments with respect to environmental matters specifically affecting EME since the filing of EME's annual report, except as set forth in "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Commitments and ContingenciesContingenciesEnvironmental Developments."
58
For a detailed discussion of EME's market risk exposures, including commodity price risk, credit risk and interest rate risk, refer to "Market Risk Exposures" in Item 7 on page 90 of EME's annual report on Form 10-K for the year ended December 31, 2009.
Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities
Energy and capacity from the fossil-fueled facilities are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City facilities. These trading hubs have been the most liquid locations for hedging purposes.
The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first six months of 2010 and 2009:
|
24-Hour Average Historical Market Prices1 |
|||||||
---|---|---|---|---|---|---|---|---|
|
2010 |
2009 |
||||||
Midwest Generation plants |
||||||||
Northern Illinois Hub |
$ | 33.44 | $ | 30.08 | ||||
Homer City facilities |
||||||||
PJM West Hub |
$ | 43.88 | $ | 41.40 | ||||
Homer City Busbar |
38.28 |
38.01 |
||||||
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at June 30, 2010:
|
24-Hour Forward Energy Prices1 | |||||||
---|---|---|---|---|---|---|---|---|
|
Northern Illinois Hub |
PJM West Hub |
||||||
2010 |
||||||||
July |
$ | 40.32 | $ | 53.39 | ||||
August |
39.34 | 52.04 | ||||||
September |
31.05 | 42.66 | ||||||
October |
26.59 | 40.15 | ||||||
November |
30.05 | 41.16 | ||||||
December |
32.43 | 44.25 | ||||||
2011 calendar "strip"2 |
$ |
32.75 |
$ |
45.54 |
||||
59
Forward market prices at the Northern Illinois Hub and PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the fossil-fueled facilities into these markets may vary materially from the forward market prices set forth in the preceding table.
EMMT engages in hedging activities for the fossil-fueled facilities to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load-serving transactions and forward contracts accounted for on the accrual basis) as of June 30, 2010 for electricity expected to be generated during the remainder of 2010 and in 2011 and 2012:
|
2010 | 2011 | 2012 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
MWh (in thousands) |
Average price/ MWh1 |
MWh (in thousands) |
Average price/ MWh1 |
MWh (in thousands) |
Average price/ MWh1 |
||||||||||||||
Midwest Generation plants |
||||||||||||||||||||
Northern Illinois and AEP/Dayton Hubs |
9,835 | $ | 42.87 | 14,152 | $ | 37.93 | 2,040 | $ | 41.37 | |||||||||||
Homer City facilities2 |
||||||||||||||||||||
PJM West Hub |
2,540 | 71.19 | 2,428 | 52.15 | 1,182 | 51.78 | ||||||||||||||
Total |
12,375 | 16,580 | 3,222 | |||||||||||||||||
In addition, as of June 30, 2010, EMMT had entered into 1.5 bcf of natural gas futures contracts (equivalent to approximately 255 GWh of energy only contracts using a ratio of 6 MMBtu to 1 MWh) for the Midwest Generation plants to economically hedge energy price risks during 2010 at an equivalent average energy price of approximately $38.40/MWh.
60
The following table summarizes the status of capacity sales for Midwest Generation and Homer City at June 30, 2010:
|
|
|
|
RPM Capacity Sold in Base Residual Auction |
Other Capacity Sales, Net of Purchases2 |
|
||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Installed Capacity MW |
Unsold Capacity1 MW |
Capacity Sold MW |
MW |
Price per MW-day |
MW |
Average Price per MW-day |
Aggregate Average Price per MW-day |
||||||||||||||||||
July 1, 2010 to May 31, 2011 Midwest Generation |
5,477 | (548 | ) | 4,929 | 4,929 | $ | 174.29 | | | $ | 174.29 | |||||||||||||||
Homer City |
1,884 | (211 | ) | 1,673 | 1,813 | 174.29 | (140 | ) | $ | 55.36 | 184.24 | |||||||||||||||
June 1, 2011 to May 31, 2012 Midwest Generation |
5,477 | (495 | ) | 4,982 | 4,582 | 110.00 | 400 | 85.00 | 107.99 | |||||||||||||||||
Homer City |
1,884 | (113 | ) | 1,771 | 1,771 | 110.00 | | | 110.00 | |||||||||||||||||
June 1, 2012 to May 31, 2013 Midwest Generation |
5,477 | (773 | ) | 4,704 | 4,704 | 16.46 | | | 16.46 | |||||||||||||||||
Homer City |
1,884 | (148 | ) | 1,736 | 1,736 | 133.37 | | | 133.37 | |||||||||||||||||
June 1, 2013 to May 31, 2014 Midwest Generation |
5,477 | (827 | ) | 4,650 | 4,650 | 27.73 | | | 27.73 | |||||||||||||||||
Homer City |
1,884 | (104 | ) | 1,780 | 1,780 | 226.15 | | | 221.03 | 3 | ||||||||||||||||
The RPM auction capacity prices for the delivery period of June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the price of $27.73 per MW-day was substantially lower than other areas' capacity prices. The impact of lower capacity prices for this period compared to previous years will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices, which is uncertain.
During the six months ended June 30, 2010, transmission congestion in PJM has resulted in prices at the individual busbars of the Midwest Generation plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 11% and 1%, respectively, compared to 17% and less than 1%, respectively, during the six months ended June 30, 2009. During the six months ended June 30, 2010 and 2009, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 13% and 8%, respectively.
61
Coal and Transportation Price Risk
The Midwest Generation plants and Homer City facilities purchase coal primarily from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at June 30, 2010 for the remainder of 2010 and the following three years:
|
Amount of Coal Under Contract in Millions of Equivalent Tons1 |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
|||||||||||||
|
July through December 2010 |
2011 |
2012 |
2013 |
|||||||||
Midwest Generation plants2 |
10.2 | 11.7 | 9.8 | | |||||||||
Homer City facilities |
2.5 | 4.2 | 1.7 | 0.5 | |||||||||
EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which are related to the price of coal purchased for the Homer City facilities, increased during 2010 from 2009 year-end prices. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) increased to a price of $62.75 per ton at July 2, 2010, compared to a price of $52.50 per ton at December 31, 2009, as reported by the Energy Information Administration.
Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content) purchased for the Midwest Generation plants increased during 2010 from 2009 year-end prices. The market price of PRB coal increased to a price of $13.05 per ton at July 2, 2010, compared to a price of $9.25 per ton at December 31, 2009, as reported by the Energy Information Administration.
EME has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through 2011. EME is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are higher than the existing rates under contract. Transportation costs are approximately half of the delivered cost of PRB coal to the Midwest Generation plants.
Emission Allowances Price Risk
EME purchases (or sells) emission allowances for the fossil-fueled facilities based on the amounts required for actual generation in excess of (or less than) the amounts allocated to these facilities under applicable programs. In the event that actual emission allowances required are greater than allowances held, EME is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO2 allowances decreased to $50 per ton during the six months ended June 30, 2010 from $65 per ton in 2009. The average purchase price of annual NOx allowances decreased to $974 per ton during the six months ended June 30, 2010 from $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price
62
for SO2 allowances and annual NOx allowances was $15 per ton and $465 per ton, respectively, at June 30, 2010.
For a discussion of environmental regulations related to emissions, refer to "Environmental Matters and Regulations" in Item 1 on page 20 of EME's annual report on Form 10-K for the year ended December 31, 2009.
The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EME's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At June 30, 2010, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:
|
June 30, 2010 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
(in millions) |
Exposure2 |
Collateral |
Net Exposure |
||||||||
Credit Rating1 |
|||||||||||
A or higher |
$ | 133 | $ | (28 | ) | $ | 105 | ||||
A- |
120 | (6 | ) | 114 | |||||||
BBB+ |
27 | | 27 | ||||||||
BBB |
23 | | 23 | ||||||||
BBB- |
23 | | 23 | ||||||||
Below investment grade |
20 | (18 | ) | 2 | |||||||
Total |
$ | 346 | $ | (52 | ) | $ | 294 | ||||
The credit risk exposure set forth in the above table is comprised of $139 million of net accounts receivable and payables and $207 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $108 million cash margin in the aggregate with PJM, New York Independent System Operator (NYISO), Midwest Independent Transmission System Operator (MISO), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.
The fossil-fueled facilities sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 67% of EME's consolidated operating revenues for the six months ended June 30, 2010. PJM, a regional transmission organization (RTO) with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At June 30, 2010, EME's account receivable due from PJM was $66 million.
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The terms of EME's wind turbine supply agreements contain significant obligations of the suppliers in the form of manufacturing and delivery of turbines, and payments for delays in delivery and for failure to meet performance obligations and warranty agreements. EME's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to EME's turbine suppliers may have a material impact on EME's wind projects and development efforts.
Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. For details, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Commitments and ContingenciesContractual ObligationsProject Financing." The fair market values of fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's consolidated construction loan and long-term obligations (including current portion) was $2.8 billion at June 30, 2010, compared to the carrying value of $4.1 billion.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
For a discussion of EME's critical accounting policies, refer to "Critical Accounting Policies and Estimates" in Item 7 on page 99 of EME's annual report on Form 10-K for the year ended December 31, 2009.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
For a discussion of market risk sensitive instruments, refer to "Fair Value of Derivative Instruments" on page 69 and "Market Risk Exposures" on page 90 in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2009. For an update to that disclosure, see "Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsResults of OperationsDerivative InstrumentsFair Value Disclosures" and "Market Risk Exposures."
ITEM 4T. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
EME's management, under the supervision and with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of EME's disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, EME's disclosure controls and procedures are effective.
Internal Control Over Financial Reporting
There were no changes in EME's internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the period to which this report relates that have materially affected, or are reasonably likely to materially affect, EME's internal control over financial reporting.
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For a discussion of EME's legal proceedings, refer to "Item 3. Legal Proceedings" on page 42 of EME's annual report on Form 10-K for the year ended December 31, 2009. There have been no significant developments with respect to legal proceedings specifically affecting EME since the filing of EME's annual report on Form 10-K for the year ended December 31, 2009, except as follows:
Midwest Generation New Source Review Lawsuit
In March 2010, the Federal District Court for the Northern District of Illinois dismissed nine of the ten counts related to PSD requirements in the complaint filed by the US EPA and the State of Illinois against Midwest Generation, holding that, as a subsequent owner, Midwest Generation could not be held liable under the PSD provisions for modifications allegedly made by Commonwealth Edison, the prior owner of the Midwest Generation plants. The Court also dismissed the tenth count to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. The decision did not address (i) 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, or (ii) the complaint in intervention filed by a group of Chicago-based environmental action groups, which also alleges opacity and particulate matter violations.
In April 2010, the US EPA formally issued to EME the same NOV that was issued to Midwest Generation in 2007. The transmittal letter stated that the action was based on a review of the asset purchase agreement for the Midwest Generation plants and that the NOV was being issued to EME as a successor in interest to Commonwealth Edison.
In June 2010, the US EPA, the State of Illinois, and several environmental groups filed amended complaints in the New Source Review litigation. The amended complaints are similar to the prior complaints, but seek to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. An August status hearing has been scheduled, at which time a schedule for responses to the amended complaints and other procedural matters will be determined.
Homer City New Source Review Notice of Violation
In May 2010, Homer City received an NOV from the US EPA. The new NOV alleges claims similar to those in the 2008 NOV, but it adds nonattainment New Source Review requirements to the alleged PSD violations. It also adds two prior owners of the Homer City facilities as parties.
In July 2010, Homer City received a 60-day Notice of Intent to Sue signed by the State of New York and the PADEP, stating their intent to file a citizen suit based on the same or similar theories advanced by the US EPA in the NOV. The Notice of Intent to Sue also named the sale-leaseback owner participants of the Homer City facilities, Homer City's general partner and limited partner, and two prior owners of the Homer City facilities.
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EME and Mitsubishi Power Systems Americas, Inc. are parties to a wind turbine generator supply agreement executed in March 2007 with respect to the purchase of 166 wind turbines and related services and warranties. Mitsubishi has delivered 83 wind turbines under the agreement. The remaining wind turbines, among other items, are under dispute.
EME filed a complaint on March 19, 2010, and an amended complaint on April 1, 2010, in the Superior Court of the State of California against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd with respect to a wind turbine generator supply agreement for the purchase of wind turbines and related services and warranties. EME's complaint alleges, among other things: (a) that the Mitsubishi entities fraudulently induced EME to enter into the supply agreement by misrepresenting the facts and circumstances surrounding Mitsubishi's rights to certain technology incorporated into the turbines; (b) that the Mitsubishi entities breached the implied covenant of good faith and fair dealing; (c) that the Mitsubishi entities breached their warranty obligations; (d) that the Mitsubishi entities repudiated the supply agreement when they failed to provide EME with adequate assurances of performance; and (e) that certain price escalation provisions in the supply agreement do not reflect the intent of the contracting parties.
The complaint asks the Court for an order finding the supply agreement void and unenforceable or, in the alternative, for an order reforming its price escalation provisions to conform to the contracting parties' intent. The complaint also requests an order of specific performance requiring the Mitsubishi entities to honor their warranties with respect to equipment already purchased, an award of monetary damages (including exemplary and punitive damages), and an accounting of all amounts due under the supply agreement, including reimbursement to EME of amounts previously paid for units it can no longer use and is excused from accepting, together with prejudgment interest, and such other relief as the Court may deem just and proper. In June 2010, EME filed a motion to amend its complaint to include, among other things, additional support for its claims.
The failure of the Mitsubishi entities to perform certain previously contracted services pertaining to the Taloga project, including delivery and commissioning of turbines still in storage, could delay the development of the Taloga project. If the Taloga project does not achieve commercial operation by March 31, 2011, subject to extension under certain circumstances, Taloga's offtaker could seek to terminate or renegotiate its power purchase agreement.
For a discussion of the risks, uncertainties, and other important factors which could materially affect EME's business, financial condition, or future results, refer to "Item 1A. Risk Factors" on page 32 of EME's annual report on Form 10-K for the year ended December 31, 2009. The risks described in EME's annual report on Form 10-K and in this report are not the only risks facing EME. Additional risks and uncertainties that are not currently known, or that are currently deemed to be immaterial, also may materially adversely affect EME's business, financial condition or future results.
Exhibit No. |
Description |
||
---|---|---|---|
31.1 | Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act. | ||
31.2 |
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act. |
||
32 |
Statement Pursuant to 18 U.S.C. Section 1350. |
||
101 |
Financial statements from the quarterly report on Form 10-Q of Edison Mission Energy for the quarter ended June 30, 2010, filed on August 5, 2010, formatted in XBRL: (i) the Consolidated Statements of Income (Loss), (ii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements tagged as blocks of text. |
||
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EDISON MISSION ENERGY | ||||
By: |
/s/ John P. Finneran, Jr. John P. Finneran, Jr. Senior Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer) |
|||
Date: |
August 5, 2010 |
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