UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended June 30, 2011
or
¨ | ||
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number | ||||||
Name of Registrant; State of Incorporation; | ||||||
Address of Principal Executive Offices; and Telephone Number | IRS Employer Identification Number | |||||
1-16169 | ||||||
EXELON CORPORATION | 23-2990190 | |||||
(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398 | ||||||
333-85496 | EXELON GENERATION COMPANY, LLC | 23-3064219 | ||||
(a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959 | ||||||
1-1839 | COMMONWEALTH EDISON COMPANY | 36-0938600 | ||||
(an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321 | ||||||
000-16844 | PECO ENERGY COMPANY | 23-0970240 | ||||
(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 |
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. Yesþ Noo¨
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). Yesþ Noo¨
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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer | Accelerated Filer | Non-accelerated Filer | Smaller | Reporting Company | ||||||||||||||||
Exelon Corporation | þ | |||||||||||||||||||
Exelon Generation Company, LLC | þ | |||||||||||||||||||
Commonwealth Edison Company | þ | |||||||||||||||||||
PECO Energy Company | þ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso¨ Noþ
The number of shares outstanding of each registrant’s common stock as of June 30, 20102011 was:
Exelon Corporation Common Stock, without par value | ||||
Exelon Generation Company, LLC | not applicable | |||
Commonwealth Edison Company Common Stock, $12.50 par value | 127,016,519 | |||
PECO Energy Company Common Stock, without par value | 170,478,507 |
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WHERE TO FIND MORE INFORMATION | 7 | ||||||||
PART I. | 8 | ||||||||
ITEM 1. | 8 | ||||||||
9 | |||||||||
Consolidated Statements of Operations and Comprehensive Income | 9 | ||||||||
Consolidated | 10 | ||||||||
11 | |||||||||
13 | |||||||||
14 | |||||||||
Consolidated Statements of Operations and Comprehensive Income | 14 | ||||||||
Consolidated | 15 | ||||||||
16 | |||||||||
18 | |||||||||
19 | |||||||||
Consolidated Statements of Operations and Comprehensive Income | 19 | ||||||||
Consolidated | 20 | ||||||||
21 | |||||||||
23 | |||||||||
24 | |||||||||
Consolidated Statements of Operations and Comprehensive Income | 24 | ||||||||
Consolidated | 25 | ||||||||
26 | |||||||||
28 | |||||||||
30 | |||||||||
31 | |||||||||
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75 |
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Page No. | ||||||||
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ITEM 2. | ||||||||
109 | ||||||||
109 | ||||||||
125 | ||||||||
145 | ||||||||
157 | ||||||||
ITEM 3. | 160 | |||||||
ITEM 4. | ||||||||
PART II. | 169 | |||||||
ITEM 1. |
| 169 | ||||||
2
169 | ||||||
ITEM 6. | 174 | |||||
SIGNATURES | 175 | |||||
175 | ||||||
175 | ||||||
176 | ||||||
176 | ||||||
CERTIFICATION EXHIBITS | 177 | |||||
Exelon Corporation | 177, 185 | |||||
Exelon Generation Company, LLC | 179, 187 | |||||
Commonwealth Edison Company | 181, 189 | |||||
PECO Energy Company | 183, 191 |
GLOSSARY OF TERMS AND ABBREVIATIONS | ||
Exelon Corporation and Related Entities | ||
Exelon | Exelon Corporation | |
Generation | Exelon Generation Company, LLC | |
ComEd | Commonwealth Edison Company | |
PECO | PECO Energy Company | |
BSC | Exelon Business Services Company, LLC | |
Exelon Corporate | Exelon’s holding company | |
Exelon Transmission Company | Exelon Transmission Company, LLC | |
Exelon Wind | Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC | |
Enterprises | Exelon Enterprises Company, LLC | |
Ventures | Exelon Ventures Company, LLC | |
AmerGen | AmerGen Energy Company, LLC | |
PEC L.P. | PECO Energy Capital, L.P. | |
PECO Trust III | PECO Capital Trust III | |
PECO Trust IV | PECO Energy Capital Trust IV | |
PETT | PECO Energy Transition Trust | |
Registrants | Exelon, Generation, ComEd, and PECO, collectively |
Other Terms and Abbreviations | ||
Note | Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s | |
1998 | PECO’s 1998 settlement of its restructuring case mandated by the Competition Act | |
Act 129 | Pennsylvania Act 129 of 2008 | |
AEC | Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source | |
AEPS Act | Pennsylvania Alternative Energy Portfolio Standards Act of 2004 | |
AFUDC | Allowance for Funds Used During Construction | |
ALJ | Administrative Law Judge | |
AMI | Advanced Metering Infrastructure | |
ARC | Asset Retirement Cost | |
ARO | Asset Retirement Obligation | |
ARP | Title IV Acid Rain Program | |
ARRA | American Recovery and Reinvestment Act of 2009 | |
ASLB | Atomic Safety Licensing Board | |
Block | Forward Purchase Energy Block Contracts | |
CAIR | Clean Air Interstate Rule | |
CAMR | Federal Clean Air Mercury Rule | |
| ||
CFL | Compact Fluorescent Light | |
Competition Act | Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996 | |
CPI | Consumer Price Index | |
CTC | Competitive Transition Charge | |
DOE | ||
DOJ | United States Department of Justice | |
DSP Program | Default Service Provider Program | |
EE&C | Energy Efficiency and Conservation/Demand | |
EGS | Electric Generation Supplier |
GLOSSARY OF TERMS AND ABBREVIATIONS | ||
Other Terms and Abbreviations | ||
EPA | Environmental Protection Agency | |
ERCOT | Electric Reliability Council of Texas | |
ERISA | Employee Retirement Income Security Act, as amended | |
EROA | Expected Rate of Return on Assets | |
ESPP | Employee Stock Purchase Plan | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
FTC | Federal Trade Commission | |
GAAP | Generally Accepted Accounting Principles in the United States | |
GHG | Greenhouse Gas | |
GSA | Generation Supply Adjustment | |
GWh | Gigawatt hour | |
HAP | Hazardous | |
HB 80 | Pennsylvania House Bill No. 80 | |
Health Care Reform Acts | Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010 | |
IBEW | International Brotherhood of Electrical Workers | |
ICC | Illinois Commerce Commission | |
ICE | Intercontinental Exchange | |
IFRS | International Financial Reporting Standards | |
Illinois Act | Illinois Electric Service Customer Choice and Rate Relief Law of 1997 | |
Illinois EPA | Illinois Environmental Protection Agency | |
Illinois Settlement Legislation | Legislation enacted in 2007 affecting electric utilities in Illinois |
3
IPA | Illinois Power Agency | |
IRC | Internal Revenue Code | |
IRS | Internal Revenue Service | |
ISO | Independent System Operator | |
ISO-NE | ISO New England Inc. | |
kV | Kilovolt | |
kW | Kilowatt | |
kWh | Kilowatt-hour | |
LIBOR | London Interbank Offered Rate | |
LILO | Lease-In, Lease-Out | |
LLRW | Low-Level Radioactive Waste | |
LTIP | Long-Term Incentive Plan | |
MGP | Manufactured Gas Plant | |
MISO | Midwest Independent Transmission System Operator, Inc. | |
mmcf | Million Cubic Feet | |
Moody’s | Moody’s Investor Service | |
MRV | Market-Related Value | |
MW | Megawatt | |
MWh | Megawatt hour | |
NAAQS | National Ambient Air Quality Standards | |
NAV | Net Asset Value | |
NDT | Nuclear Decommissioning Trust | |
NEIL | Nuclear Electric Insurance Limited | |
NERC | North American Electric Reliability Corporation | |
NJDEP | New Jersey Department of Environmental Protection |
Other Terms and Abbreviations | ||
| Former AmerGen nuclear generating units and portions of the Peach Bottom nuclear generating units whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting | |
NOV | Notice of Violation | |
NPDES | National Pollutant Discharge Elimination System | |
NRC | Nuclear Regulatory Commission | |
NWPA | Nuclear Waste Policy Act of 1982 | |
NYMEX | New York Mercantile Exchange | |
OCI | Other Comprehensive Income | |
OPEB | Other Postretirement Employee Benefits | |
PA DEP | Pennsylvania Department of Environmental Protection | |
PAPUC | Pennsylvania Public Utility Commission | |
PCCA | Pennsylvania Climate Change Act | |
PGC | Purchased Gas Cost Clause | |
PJM | PJM Interconnection, LLC | |
POLR | Provider of Last Resort | |
POR | Purchase of Receivables | |
PPA | Power Purchase Agreement | |
Prescription Drug Act | Medicare Prescription Drug Improvement and Modernization Drug Act of 2003 | |
PRP | Potentially Responsible | |
PSEG | Public Service Enterprise Group Incorporated | |
PUHCA | Public Utility Holding Company Act of 1935 | |
PURTA | Pennsylvania Public | |
RCRA | Federal Resource Conservation and Recovery Act | |
REC | Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source | |
Regulatory Agreement Units | Former ComEd and former PECO nuclear generating units whose decommissioning-related activities are subject to contractual elimination under regulatory accounting | |
RES | Retail Electric Suppliers | |
RFP | Request for Proposal | |
RGGI | Regional Greenhouse Gas Initiative | |
Rider | Reconcilable Surcharge Recovery Mechanism | |
RMC | Risk Management Committee | |
RPS | Renewable Energy Portfolio Standards | |
RPM | PJM Reliability Pricing Model | |
RTEP | Regional Transmission Expansion Plan | |
RTO | Regional Transmission Organization | |
S&P | Standard & Poor’s Ratings Services | |
SEC | United States Securities and Exchange Commission | |
SECA | Seams Elimination Charge/Cost Adjustments/Assignment | |
SERP | Supplemental Employee Retirement Plan | |
SFC | Supplier Forward Contract | |
SGIG | Smart Grid Investment Grant | |
SILO | Sale-In, Lease-Out | |
SMP | Smart Meter Program | |
SNF | Spent Nuclear Fuel | |
SSCM | Simplified Service Cost Method |
Other Terms and Abbreviations | ||
Tax Relief Act of 2010 | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 | |
TEG | Termoelectrica del Golfo | |
TEP | Termoelectrica Penoles | |
VIE | Variable Interest Entity |
4
This combined Form 10-Q is being filed separately by the Registrants. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.
Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrantRegistrant include (a) those factors discussed in the following sections of the Registrants’ 20092010 Annual Report on Form 10-K: ITEM 1A. Risk Factors, as updated by Part II, ITEM 1A of this Report; ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as updated by Part I, ITEM 2. of this Report; and ITEM 8. Financial Statements and Supplementary Data: Note 18, as updated by Part I, Item 1. Financial Statements, Note 1213 of this Report; and (b) other factors discussed herein and in other filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the website maintained by the SEC atwww.sec.gov and the Registrants’ websites atwww.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.
5
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(In millions, except per share data) | 2010 | 2009 | 2010 | 2009 | ||||||||||||
Operating revenues | $ | 4,398 | $ | 4,141 | $ | 8,859 | $ | 8,863 | ||||||||
Operating expenses | ||||||||||||||||
Purchased power | 1,134 | 921 | 1,792 | 1,604 | ||||||||||||
Fuel | 393 | 460 | 994 | 1,236 | ||||||||||||
Operating and maintenance | 1,114 | 1,111 | 2,175 | 2,472 | ||||||||||||
Operating and maintenance for regulatory required programs | 34 | 14 | 61 | 25 | ||||||||||||
Depreciation and amortization | 519 | 439 | 1,033 | 875 | ||||||||||||
Taxes other than income | 186 | 180 | 383 | 380 | ||||||||||||
Total operating expenses | 3,380 | 3,125 | 6,438 | 6,592 | ||||||||||||
Operating income | 1,018 | 1,016 | 2,421 | 2,271 | ||||||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (269 | ) | (159 | ) | (446 | ) | (323 | ) | ||||||||
Interest expense to affiliates, net | (6 | ) | (21 | ) | (13 | ) | (44 | ) | ||||||||
Loss in equity method investments | — | (6 | ) | — | (14 | ) | ||||||||||
Other, net | (122 | ) | 257 | (29 | ) | 219 | ||||||||||
Total other income and deductions | (397 | ) | 71 | (488 | ) | (162 | ) | |||||||||
Income before income taxes | 621 | 1,087 | 1,933 | 2,109 | ||||||||||||
Income taxes | 176 | 430 | 739 | 740 | ||||||||||||
Net income | 445 | 657 | 1,194 | 1,369 | ||||||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||
Prior service benefit reclassified to periodic benefit cost | 3 | 2 | (6 | ) | (6 | ) | ||||||||||
Actuarial loss reclassified to periodic cost | 24 | 17 | 57 | 45 | ||||||||||||
Transition obligation reclassified to periodic cost | — | — | 2 | 1 | ||||||||||||
Pension and non-pension postretirement benefit plans valuation adjustment | (2 | ) | — | (16 | ) | 28 | ||||||||||
Change in unrealized gain (loss) on cash-flow hedges | (409 | ) | (220 | ) | (26 | ) | 305 | |||||||||
Change in unrealized gain on marketable securities | — | 8 | — | 5 | ||||||||||||
Other comprehensive income (loss) | (384 | ) | (193 | ) | 11 | 378 | ||||||||||
Comprehensive income | $ | 61 | $ | 464 | $ | 1,205 | $ | 1,747 | ||||||||
Average shares of common stock outstanding: | ||||||||||||||||
Basic | 661 | 659 | 661 | 659 | ||||||||||||
Diluted | 662 | 661 | 662 | 661 | ||||||||||||
Earnings per average common share: | ||||||||||||||||
Basic | $ | 0.67 | $ | 1.00 | $ | 1.81 | $ | 2.08 | ||||||||
Diluted | $ | 0.67 | $ | 0.99 | $ | 1.80 | $ | 2.07 | ||||||||
Dividends per common share | $ | 0.53 | $ | 0.53 | $ | 1.05 | $ | 1.05 | ||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(In millions, except per share data) | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Operating revenues | $ | 4,587 | $ | 4,398 | $ | 9,638 | $ | 8,859 | ||||||||
Operating expenses | ||||||||||||||||
Purchased power | 1,407 | 1,134 | 2,891 | 1,792 | ||||||||||||
Fuel | 400 | 393 | 1,012 | 994 | ||||||||||||
Operating and maintenance | 1,185 | 1,114 | 2,370 | 2,175 | ||||||||||||
Operating and maintenance for regulatory required programs | 41 | 34 | 79 | 61 | ||||||||||||
Depreciation and amortization | 329 | 519 | 656 | 1,033 | ||||||||||||
Taxes other than income | 191 | 186 | 394 | 383 | ||||||||||||
Total operating expenses | 3,553 | 3,380 | 7,402 | 6,438 | ||||||||||||
Operating income | 1,034 | 1,018 | 2,236 | 2,421 | ||||||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (176 | ) | (269 | ) | (350 | ) | (446 | ) | ||||||||
Interest expense to affiliates, net | (6 | ) | (6 | ) | (13 | ) | (13 | ) | ||||||||
Other, net | 100 | (122 | ) | 194 | (29 | ) | ||||||||||
Total other income and deductions | (82 | ) | (397 | ) | (169 | ) | (488 | ) | ||||||||
Income before income taxes | 952 | 621 | 2,067 | 1,933 | ||||||||||||
Income taxes | 332 | 176 | 779 | 739 | ||||||||||||
Net income | 620 | 445 | 1,288 | 1,194 | ||||||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||
Prior service benefit reclassified to periodic benefit cost | (1 | ) | 3 | (2 | ) | (6 | ) | |||||||||
Actuarial loss reclassified to periodic cost | 34 | 24 | 66 | 57 | ||||||||||||
Transition obligation reclassified to periodic cost | 1 | — | 2 | 2 | ||||||||||||
Pension and non-pension postretirement benefit plans valuation adjustment | — | (2 | ) | 39 | (16 | ) | ||||||||||
Change in unrealized loss on cash flow hedges | (145 | ) | (409 | ) | (191 | ) | (26 | ) | ||||||||
Other comprehensive income (loss) | (111 | ) | (384 | ) | (86 | ) | 11 | |||||||||
Comprehensive income | $ | 509 | $ | 61 | $ | 1,202 | $ | 1,205 | ||||||||
Average shares of common stock outstanding: | ||||||||||||||||
Basic | 663 | 661 | 663 | 661 | ||||||||||||
Diluted | 664 | 662 | 664 | 662 | ||||||||||||
Earnings per average common share: | ||||||||||||||||
Basic | $ | 0.93 | $ | 0.67 | $ | 1.94 | $ | 1.81 | ||||||||
Diluted | $ | 0.93 | $ | 0.67 | $ | 1.94 | $ | 1.80 | ||||||||
Dividends per common share | $ | 0.53 | $ | 0.53 | $ | 1.05 | $ | 1.05 | ||||||||
See the Combined Notes to Consolidated Financial Statements
7
(Unaudited)
Six Months Ended | |||||||||
June 30, | |||||||||
(In millions) | 2010 | 2009 | |||||||
Cash flows from operating activities | |||||||||
Net income | $ | 1,194 | $ | 1,369 | |||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | |||||||||
Depreciation, amortization and accretion, including nuclear fuel amortization | 1,455 | 1,253 | |||||||
Impairment of long-lived assets | — | 223 | |||||||
Deferred income taxes and amortization of investment tax credits | (373 | ) | 149 | ||||||
Net fair value changes related to derivatives | (123 | ) | 28 | ||||||
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | 59 | (43 | ) | ||||||
Other non-cash operating activities | 278 | 411 | |||||||
Changes in assets and liabilities: | |||||||||
Accounts receivable | (229 | ) | 286 | ||||||
Inventories | 1 | 75 | |||||||
Accounts payable, accrued expenses and other current liabilities | (239 | ) | (469 | ) | |||||
Option premiums paid, net | (15 | ) | (39 | ) | |||||
Counterparty collateral (posted) received, net | (172 | ) | 246 | ||||||
Income taxes | 661 | (177 | ) | ||||||
Pension and non-pension postretirement benefit contributions | (119 | ) | (68 | ) | |||||
Other assets and liabilities | (9 | ) | (197 | ) | |||||
Net cash flows provided by operating activities | 2,369 | 3,047 | |||||||
Cash flows from investing activities | |||||||||
Capital expenditures | (1,584 | ) | (1,444 | ) | |||||
Proceeds from nuclear decommissioning trust fund sales | 12,528 | 10,150 | |||||||
Investment in nuclear decommissioning trust funds | (12,626 | ) | (10,279 | ) | |||||
Change in restricted cash | (6 | ) | 31 | ||||||
Other investing activities | 30 | (4 | ) | ||||||
Net cash flows used in investing activities | (1,658 | ) | (1,546 | ) | |||||
Cash flows from financing activities | |||||||||
Changes in short-term debt | 134 | (166 | ) | ||||||
Issuance of long-term debt | — | 485 | |||||||
Retirement of long-term debt | (615 | ) | (255 | ) | |||||
Retirement of long-term debt of variable interest entity | (402 | ) | — | ||||||
Retirement of long-term debt to financing affiliates | — | (330 | ) | ||||||
Dividends paid on common stock | (694 | ) | (692 | ) | |||||
Proceeds from employee stock plans | 22 | 19 | |||||||
Other financing activities | 2 | 5 | |||||||
Net cash flows used in financing activities | (1,553 | ) | (934 | ) | |||||
Increase (decrease) in cash and cash equivalents | (842 | ) | 567 | ||||||
Cash and cash equivalents at beginning of period | 2,010 | 1,271 | |||||||
Cash and cash equivalents at end of period | $ | 1,168 | $ | 1,838 | |||||
Six Months Ended June 30, | ||||||||
(In millions) | 2011 | 2010 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 1,288 | $ | 1,194 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion, including nuclear fuel amortization | 1,114 | 1,455 | ||||||
Deferred income taxes and amortization of investment tax credits | 590 | (373 | ) | |||||
Net fair value changes related to derivatives | 264 | (123 | ) | |||||
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | (51 | ) | 59 | |||||
Other non-cash operating activities | 378 | 278 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | — | (229 | ) | |||||
Inventories | 17 | 1 | ||||||
Accounts payable, accrued expenses and other current liabilities | (486 | ) | (239 | ) | ||||
Option premiums received (paid), net | 38 | (15 | ) | |||||
Counterparty collateral posted, net | (494 | ) | (172 | ) | ||||
Income taxes | 691 | 661 | ||||||
Pension and non-pension postretirement benefit contributions | (2,089 | ) | (119 | ) | ||||
Other assets and liabilities | (247 | ) | (9 | ) | ||||
Net cash flows provided by operating activities | 1,013 | 2,369 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (1,985 | ) | (1,584 | ) | ||||
Proceeds from nuclear decommissioning trust fund sales | 1,657 | 1,799 | ||||||
Investment in nuclear decommissioning trust funds | (1,772 | ) | (1,897 | ) | ||||
Change in restricted cash | (2 | ) | (6 | ) | ||||
Other investing activities | 28 | 30 | ||||||
Net cash flows used in investing activities | (2,074 | ) | (1,658 | ) | ||||
Cash flows from financing activities | ||||||||
Changes in short-term debt | 140 | 134 | ||||||
Issuance of long-term debt | 599 | — | ||||||
Retirement of long-term debt | (2 | ) | (615 | ) | ||||
Retirement of long-term debt of variable interest entity | — | (402 | ) | |||||
Dividends paid on common stock | (695 | ) | (694 | ) | ||||
Proceeds from employee stock plans | 15 | 22 | ||||||
Other financing activities | (46 | ) | 2 | |||||
Net cash flows provided by (used in) financing activities | 11 | (1,553 | ) | |||||
Decrease in cash and cash equivalents | (1,050 | ) | (842 | ) | ||||
Cash and cash equivalents at beginning of period | 1,612 | 2,010 | ||||||
Cash and cash equivalents at end of period | $ | 562 | $ | 1,168 | ||||
See the Combined Notes to Consolidated Financial Statements
8
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, | December 31, | |||||||
(In millions) | 2010 | 2009 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 1,168 | $ | 2,010 | ||||
Restricted cash and investments | 33 | 40 | ||||||
Restricted cash and cash equivalents of variable interest entity | 426 | — | ||||||
Accounts receivable, net | ||||||||
Customer ($366 gross accounts receivable pledged as collateral as of June 30, 2010) | 1,886 | 1,563 | ||||||
Other | 451 | 486 | ||||||
Mark-to-market derivative assets | 418 | 376 | ||||||
Inventories, net | ||||||||
Fossil fuel | 174 | 198 | ||||||
Materials and supplies | 585 | 559 | ||||||
Other | 459 | 209 | ||||||
Total current assets | 5,600 | 5,441 | ||||||
Property, plant and equipment, net | 28,030 | 27,341 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 4,380 | 4,872 | ||||||
Nuclear decommissioning trust funds | 6,498 | 6,669 | ||||||
Investments | 708 | 704 | ||||||
Investments in affiliates | 15 | 20 | ||||||
Goodwill | 2,625 | 2,625 | ||||||
Mark-to-market derivative assets | 627 | 649 | ||||||
Other | 690 | 859 | ||||||
Total deferred debits and other assets | 15,543 | 16,398 | ||||||
Total assets | $ | 49,173 | $ | 49,180 | ||||
(In millions) | June 30, 2011 | December 31, 2010 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 562 | $ | 1,612 | ||||
Restricted cash and investments | 35 | 30 | ||||||
Accounts receivable, net | ||||||||
Customer ($309 and $346 gross accounts receivable pledged as collateral as of June 30, 2011 and December 31, 2010, respectively) | 1,766 | 1,932 | ||||||
Other | 697 | 1,196 | ||||||
Mark-to-market derivative assets | 438 | 487 | ||||||
Inventories, net | ||||||||
Fossil fuel | 161 | 216 | ||||||
Materials and supplies | 625 | 590 | ||||||
Deferred income taxes | 69 | — | ||||||
Regulatory assets | 125 | 10 | ||||||
Other | 509 | 325 | ||||||
Total current assets | 4,987 | 6,398 | ||||||
Property, plant and equipment, net | 30,856 | 29,941 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 4,189 | 4,140 | ||||||
Nuclear decommissioning trust funds | 6,699 | 6,408 | ||||||
Investments | 736 | 717 | ||||||
Investments in affiliates | 15 | 15 | ||||||
Goodwill | 2,625 | 2,625 | ||||||
Mark-to-market derivative assets | 324 | 409 | ||||||
Pledged assets for Zion Station decommissioning | 804 | 824 | ||||||
Other | 751 | 763 | ||||||
Total deferred debits and other assets | 16,143 | 15,901 | ||||||
Total assets | $ | 51,986 | $ | 52,240 | ||||
See the Combined Notes to Consolidated Financial Statements
9
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, | December 31, | |||||||
(In millions) | 2010 | 2009 | ||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term borrowings | $ | 289 | $ | 155 | ||||
Short-term notes payable — accounts receivable agreement | 225 | — | ||||||
Long-term debt due within one year | 215 | 639 | ||||||
Long-term debt of variable interest entity due within one year | 404 | — | ||||||
Long-term debt to PECO Energy Transition Trust due within one year | — | 415 | ||||||
Accounts payable | 1,181 | 1,345 | ||||||
Accrued expenses | 1,098 | 923 | ||||||
Deferred income taxes | 114 | 152 | ||||||
Mark-to-market derivative liabilities | 54 | 198 | ||||||
Other | 450 | 411 | ||||||
Total current liabilities | 4,030 | 4,238 | ||||||
Long-term debt | 10,811 | 10,995 | ||||||
Long-term debt to financing trusts | 390 | 390 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 5,474 | 5,750 | ||||||
Asset retirement obligations | 3,527 | 3,434 | ||||||
Pension obligations | 3,527 | 3,625 | ||||||
Non-pension postretirement benefit obligations | 2,278 | 2,180 | ||||||
Spent nuclear fuel obligation | 1,018 | 1,017 | ||||||
Regulatory liabilities | 3,344 | 3,492 | ||||||
Mark-to-market derivative liabilities | 8 | 23 | ||||||
Other | 1,493 | 1,309 | ||||||
Total deferred credits and other liabilities | 20,669 | 20,830 | ||||||
Total liabilities | 35,900 | 36,453 | ||||||
Commitments and contingencies | ||||||||
Preferred securities of subsidiary | 87 | 87 | ||||||
Shareholders’ equity | ||||||||
Common stock (No par value, 2,000 shares authorized, 661 and 660 shares outstanding at June 30, 2010 and December 31, 2009, respectively) | 8,960 | 8,923 | ||||||
Treasury stock, at cost (35 and 35 shares held at June 30, 2010 and December 31, 2009, respectively) | (2,327 | ) | (2,328 | ) | ||||
Retained earnings | 8,631 | 8,134 | ||||||
Accumulated other comprehensive loss, net | (2,078 | ) | (2,089 | ) | ||||
Total shareholders’ equity | 13,186 | 12,640 | ||||||
Total liabilities and shareholders’ equity | $ | 49,173 | $ | 49,180 | ||||
(In millions) | June 30, 2011 | December 31, 2010 | ||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term borrowings | $ | 140 | $ | — | ||||
Short-term notes payable — accounts receivable agreement | 225 | 225 | ||||||
Long-term debt due within one year | 1,048 | 599 | ||||||
Accounts payable | 1,297 | 1,373 | ||||||
Accrued expenses | 878 | 1,040 | ||||||
Deferred income taxes | — | 85 | ||||||
Regulatory liabilities | 63 | 44 | ||||||
Mark-to-market derivative liabilities | 50 | 38 | ||||||
Other | 567 | 836 | ||||||
Total current liabilities | 4,268 | 4,240 | ||||||
Long-term debt | 11,764 | 11,614 | ||||||
Long-term debt to financing trusts | 390 | 390 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 7,391 | 6,621 | ||||||
Asset retirement obligations | 3,597 | 3,494 | ||||||
Pension obligations | 1,495 | 3,658 | ||||||
Non-pension postretirement benefit obligations | 2,311 | 2,218 | ||||||
Spent nuclear fuel obligation | 1,019 | 1,018 | ||||||
Regulatory liabilities | 3,706 | 3,555 | ||||||
Mark-to-market derivative liabilities | 66 | 21 | ||||||
Payable for Zion Station decommissioning | 640 | 659 | ||||||
Other | 1,137 | 1,102 | ||||||
Total deferred credits and other liabilities | 21,362 | 22,346 | ||||||
Total liabilities | 37,784 | 38,590 | ||||||
Commitments and contingencies | ||||||||
Preferred securities of subsidiary | 87 | 87 | ||||||
Shareholders’ equity | ||||||||
Common stock (No par value, 2,000 shares authorized, 663 shares outstanding at June 30, 2011 and 662 shares outstanding at December 31, 2010, respectively) | 9,054 | 9,006 | ||||||
Treasury stock, at cost (35 shares at June 30, 2011 and December 31, 2010, respectively) | (2,327 | ) | (2,327 | ) | ||||
Retained earnings | 9,894 | 9,304 | ||||||
Accumulated other comprehensive loss, net | (2,509 | ) | (2,423 | ) | ||||
Total shareholders’ equity | 14,112 | 13,560 | ||||||
Noncontrolling interest | 3 | 3 | ||||||
Total equity | 14,115 | 13,563 | ||||||
Total liabilities and shareholders’ equity | $ | 51,986 | $ | 52,240 | ||||
See the Combined Notes to Consolidated Financial Statements
10
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Accumulated Other | Total | |||||||||||||||||||||||
Issued | Common | Treasury | Retained | Comprehensive | Shareholders’ | |||||||||||||||||||
(In millions, shares in thousands) | Shares | Stock | Stock | Earnings | Loss, net | Equity | ||||||||||||||||||
Balance, December 31, 2009 | 694,565 | $ | 8,923 | $ | (2,328 | ) | $ | 8,134 | $ | (2,089 | ) | $ | 12,640 | |||||||||||
Net income | — | — | — | 1,194 | — | 1,194 | ||||||||||||||||||
Long-term incentive plan activity | 1,173 | 37 | 1 | (1 | ) | — | 37 | |||||||||||||||||
Common stock dividends | — | — | — | (696 | ) | — | (696 | ) | ||||||||||||||||
Other comprehensive income, net of income taxes of $7 | — | — | — | — | 11 | 11 | ||||||||||||||||||
Balance, June 30, 2010 | 695,738 | $ | 8,960 | $ | (2,327 | ) | $ | 8,631 | $ | (2,078 | ) | $ | 13,186 | |||||||||||
(In millions, shares in thousands) | Issued Shares | Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Loss, net | Noncontrolling Interest | Total Equity | |||||||||||||||||||||
Balance, December 31, 2010 | 696,589 | $ | 9,006 | $ | (2,327 | ) | $ | 9,304 | $ | (2,423 | ) | $ | 3 | $ | 13,563 | |||||||||||||
Net income | — | — | — | 1,288 | — | — | 1,288 | |||||||||||||||||||||
Long-term incentive plan activity | 846 | 48 | — | — | — | — | 48 | |||||||||||||||||||||
Common stock dividends | — | — | — | (698 | ) | — | — | (698 | ) | |||||||||||||||||||
Other comprehensive loss net of income taxes of $52 | — | — | — | — | (86 | ) | — | (86 | ) | |||||||||||||||||||
Balance, June 30, 2011 | 697,435 | $ | 9,054 | $ | (2,327 | ) | $ | 9,894 | $ | (2,509 | ) | $ | 3 | $ | 14,115 | |||||||||||||
See the Combined Notes to Consolidated Financial Statements
11
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(In millions) | 2010 | 2009 | 2010 | 2009 | ||||||||||||
Operating revenues | ||||||||||||||||
Operating revenues | $ | 1,628 | $ | 1,545 | $ | 3,221 | $ | 3,202 | ||||||||
Operating revenues from affiliates | 725 | 833 | 1,552 | 1,777 | ||||||||||||
Total operating revenues | 2,353 | 2,378 | 4,773 | 4,979 | ||||||||||||
Operating expenses | ||||||||||||||||
Purchased power | 549 | 485 | 757 | 660 | ||||||||||||
Fuel | 350 | 406 | 740 | 915 | ||||||||||||
Operating and maintenance | 621 | 605 | 1,285 | 1,453 | ||||||||||||
Operating and maintenance from affiliates | 70 | 84 | 147 | 164 | ||||||||||||
Depreciation and amortization | 115 | 72 | 223 | 149 | ||||||||||||
Taxes other than income | 61 | 50 | 118 | 100 | ||||||||||||
Total operating expenses | 1,766 | 1,702 | 3,270 | 3,441 | ||||||||||||
Operating income | 587 | 676 | 1,503 | 1,538 | ||||||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (37 | ) | (24 | ) | (72 | ) | (52 | ) | ||||||||
Loss in equity method investments | — | — | — | (1 | ) | |||||||||||
Other, net | (133 | ) | 215 | (54 | ) | 133 | ||||||||||
Total other income and deductions | (170 | ) | 191 | (126 | ) | 80 | ||||||||||
Income before income taxes | 417 | 867 | 1,377 | 1,618 | ||||||||||||
Income taxes | 35 | 355 | 434 | 577 | ||||||||||||
Net income | 382 | 512 | 943 | 1,041 | ||||||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||
Change in unrealized gain (loss) on cash-flow hedges | (545 | ) | (302 | ) | 6 | 657 | ||||||||||
Other comprehensive income (loss) | (545 | ) | (302 | ) | 6 | 657 | ||||||||||
Comprehensive income (loss) | $ | (163 | ) | $ | 210 | $ | 949 | $ | 1,698 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(In millions) | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Operating revenues | ||||||||||||||||
Operating revenues | $ | 2,300 | $ | 1,628 | $ | 4,733 | $ | 3,221 | ||||||||
Operating revenues from affiliates | 246 | 725 | 552 | 1,552 | ||||||||||||
Total operating revenues | 2,546 | 2,353 | 5,285 | 4,773 | ||||||||||||
Operating expenses | ||||||||||||||||
Purchased power | 572 | 549 | 1,121 | 757 | ||||||||||||
Fuel | 360 | 350 | 790 | 740 | ||||||||||||
Operating and maintenance | 692 | 621 | 1,372 | 1,285 | ||||||||||||
Operating and maintenance from affiliates | 71 | 70 | 145 | 147 | ||||||||||||
Depreciation and amortization | 138 | 115 | 277 | 223 | ||||||||||||
Taxes other than income | 66 | 61 | 132 | 118 | ||||||||||||
Total operating expenses | 1,899 | 1,766 | 3,837 | 3,270 | ||||||||||||
Operating income | 647 | 587 | 1,448 | 1,503 | ||||||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (45 | ) | (37 | ) | (91 | ) | (72 | ) | ||||||||
Other, net | 76 | (133 | ) | 152 | (54 | ) | ||||||||||
Total other income and deductions | 31 | (170 | ) | 61 | (126 | ) | ||||||||||
Income before income taxes | 678 | 417 | 1,509 | 1,377 | ||||||||||||
Income taxes | 235 | 35 | 571 | 434 | ||||||||||||
Net income | 443 | 382 | 938 | 943 | ||||||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||
Change in unrealized gain (loss) on cash flow hedges | (254 | ) | (545 | ) | (323 | ) | 6 | |||||||||
Other comprehensive income (loss) | (254 | ) | (545 | ) | (323 | ) | 6 | |||||||||
Comprehensive income (loss) | $ | 189 | $ | (163 | ) | $ | 615 | $ | 949 | |||||||
See the Combined Notes to Consolidated Financial Statements
12
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended | ||||||||
June 30, | ||||||||
(In millions) | 2010 | 2009 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 943 | $ | 1,041 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion, including nuclear fuel amortization | 645 | 526 | ||||||
Impairment of long-lived assets | — | 223 | ||||||
Deferred income taxes and amortization of investment tax credits | (34 | ) | 100 | |||||
Net fair value changes related to derivatives | (123 | ) | 28 | |||||
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | 59 | (43 | ) | |||||
Other non-cash operating activities | 133 | 113 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | — | 174 | ||||||
Receivables from and payables to affiliates, net | 70 | (47 | ) | |||||
Inventories | (27 | ) | 1 | |||||
Accounts payable, accrued expenses and other current liabilities | (203 | ) | (186 | ) | ||||
Option premiums paid, net | (15 | ) | (39 | ) | ||||
Counterparty collateral (posted) received, net | (54 | ) | 245 | |||||
Income taxes | 158 | (68 | ) | |||||
Pension and non-pension postretirement benefit contributions | (65 | ) | (33 | ) | ||||
Other assets and liabilities | (34 | ) | (21 | ) | ||||
Net cash flows provided by operating activities | 1,453 | 2,014 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (982 | ) | (801 | ) | ||||
Proceeds from nuclear decommissioning trust fund sales | 12,528 | 10,150 | ||||||
Investment in nuclear decommissioning trust funds | (12,626 | ) | (10,279 | ) | ||||
Change in restricted cash | 2 | 11 | ||||||
Other investing activities | 3 | (7 | ) | |||||
Net cash flows used in investing activities | (1,075 | ) | (926 | ) | ||||
Cash flows from financing activities | ||||||||
Issuance of long-term debt | — | 46 | ||||||
Retirement of long-term debt | (214 | ) | (47 | ) | ||||
Distribution to member | (417 | ) | (675 | ) | ||||
Other financing activities | 2 | 2 | ||||||
Net cash flows used in financing activities | (629 | ) | (674 | ) | ||||
Increase (decrease) in cash and cash equivalents | (251 | ) | 414 | |||||
Cash and cash equivalents at beginning of period | 1,099 | 1,135 | ||||||
Cash and cash equivalents at end of period | $ | 848 | $ | 1,549 | ||||
Six Months Ended June 30, | ||||||||
(In millions) | 2011 | 2010 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 938 | $ | 943 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion, including nuclear fuel amortization | 735 | 645 | ||||||
Deferred income taxes and amortization of investment tax credits | 298 | (34 | ) | |||||
Net fair value changes related to derivatives | 264 | (123 | ) | |||||
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | (51 | ) | 59 | |||||
Other non-cash operating activities | 168 | 133 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (139 | ) | — | |||||
Receivables from and payables to affiliates, net | 223 | 70 | ||||||
Inventories | (5 | ) | (27 | ) | ||||
Accounts payable, accrued expenses and other current liabilities | (78 | ) | (203 | ) | ||||
Option premiums received (paid), net | 38 | (15 | ) | |||||
Counterparty collateral paid, net | (525 | ) | (54 | ) | ||||
Income taxes | 270 | 158 | ||||||
Pension and non-pension postretirement benefit contributions | (952 | ) | (65 | ) | ||||
Other assets and liabilities | (108 | ) | (34 | ) | ||||
Net cash flows provided by operating activities | 1,076 | 1,453 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (1,270 | ) | (982 | ) | ||||
Proceeds from nuclear decommissioning trust fund sales | 1,657 | 1,799 | ||||||
Investment in nuclear decommissioning trust funds | (1,772 | ) | (1,897 | ) | ||||
Change in restricted cash | — | 2 | ||||||
Other investing activities | (3 | ) | 3 | |||||
Net cash flows used in investing activities | (1,388 | ) | (1,075 | ) | ||||
Cash flows from financing activities | ||||||||
Retirement of long-term debt | (1 | ) | (214 | ) | ||||
Distribution to member | — | (417 | ) | |||||
Other financing activities | (34 | ) | 2 | |||||
Net cash flows used in financing activities | (35 | ) | (629 | ) | ||||
Decrease in cash and cash equivalents | (347 | ) | (251 | ) | ||||
Cash and cash equivalents at beginning of period | 456 | 1,099 | ||||||
Cash and cash equivalents at end of period | $ | 109 | $ | 848 | ||||
See the Combined Notes to Consolidated Financial Statements
13
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, | December 31, | |||||||
(In millions) | 2010 | 2009 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 848 | $ | 1,099 | ||||
Restricted cash and cash equivalents | 3 | 5 | ||||||
Accounts receivable, net | ||||||||
Customer | 430 | 495 | ||||||
Other | 176 | 112 | ||||||
Mark-to-market derivative assets | 418 | 376 | ||||||
Mark-to-market derivative assets with affiliates | 386 | 302 | ||||||
Receivables from affiliates | 238 | 297 | ||||||
Inventories, net | ||||||||
Fossil fuel | 108 | 102 | ||||||
Materials and supplies | 494 | 470 | ||||||
Other | 159 | 102 | ||||||
Total current assets | 3,260 | 3,360 | ||||||
Property, plant and equipment, net | 10,221 | 9,809 | ||||||
Deferred debits and other assets | ||||||||
Nuclear decommissioning trust funds | 6,498 | 6,669 | ||||||
Investments | 42 | 46 | ||||||
Mark-to-market derivative assets | 612 | 639 | ||||||
Mark-to-market derivative assets with affiliates | 629 | 671 | ||||||
Prepaid pension asset | 1,018 | 1,027 | ||||||
Other | 219 | 185 | ||||||
Total deferred debits and other assets | 9,018 | 9,237 | ||||||
Total assets | $ | 22,499 | $ | 22,406 | ||||
(In millions) | June 30, 2011 | December 31, 2010 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 109 | $ | 456 | ||||
Restricted cash and cash equivalents | 1 | 1 | ||||||
Accounts receivable, net | ||||||||
Customer | 582 | 469 | ||||||
Other | 200 | 161 | ||||||
Mark-to-market derivative assets | 438 | 487 | ||||||
Mark-to-market derivative assets with affiliates | 414 | 455 | ||||||
Receivables from affiliates | 86 | 306 | ||||||
Inventories, net | ||||||||
Fossil fuel | 104 | 129 | ||||||
Materials and supplies | 527 | 500 | ||||||
Other | 215 | 123 | ||||||
Total current assets | 2,676 | 3,087 | ||||||
Property, plant and equipment, net | 12,224 | 11,662 | ||||||
Deferred debits and other assets | ||||||||
Nuclear decommissioning trust funds | 6,699 | 6,408 | ||||||
Investments | 38 | 35 | ||||||
Mark-to-market derivative assets | 310 | 391 | ||||||
Mark-to-market derivative assets with affiliates | 345 | 525 | ||||||
Prepaid pension asset | 2,127 | 1,236 | ||||||
Pledged assets for Zion Station decommissioning | 804 | 824 | ||||||
Other | 410 | 366 | ||||||
Total deferred debits and other assets | 10,733 | 9,785 | ||||||
Total assets | $ | 25,633 | $ | 24,534 | ||||
See the Combined Notes to Consolidated Financial Statements
14
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, | December 31, | |||||||
(In millions) | 2010 | 2009 | ||||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities | ||||||||
Long-term debt due within one year | $ | 2 | $ | 26 | ||||
Accounts payable | 637 | 826 | ||||||
Accrued expenses | 796 | 670 | ||||||
Payables to affiliates | 55 | 80 | ||||||
Deferred income taxes | 405 | 399 | ||||||
Mark-to-market derivative liabilities | 46 | 198 | ||||||
Other | 81 | 63 | ||||||
Total current liabilities | 2,022 | 2,262 | ||||||
Long-term debt | 2,777 | 2,967 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 2,676 | 2,707 | ||||||
Asset retirement obligations | 3,406 | 3,316 | ||||||
Non-pension postretirement benefit obligations | 720 | 659 | ||||||
Spent nuclear fuel obligation | 1,018 | 1,017 | ||||||
Payables to affiliates | 2,069 | 2,228 | ||||||
Mark-to-market derivative liabilities | 6 | 21 | ||||||
Other | 480 | 437 | ||||||
Total deferred credits and other liabilities | 10,375 | 10,385 | ||||||
Total liabilities | 15,174 | 15,614 | ||||||
Commitments and contingencies | ||||||||
Equity | ||||||||
Member’s equity | ||||||||
Membership interest | 3,465 | 3,464 | ||||||
Undistributed earnings | 2,695 | 2,169 | ||||||
Accumulated other comprehensive income, net | 1,163 | 1,157 | ||||||
Total member’s equity | 7,323 | 6,790 | ||||||
Noncontrolling interest | 2 | 2 | ||||||
Total equity | 7,325 | 6,792 | ||||||
Total liabilities and equity | $ | 22,499 | $ | 22,406 | ||||
(In millions) | June 30, 2011 | December 31, 2010 | ||||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities | ||||||||
Long-term debt due within one year | $ | 3 | $ | 3 | ||||
Accounts payable | 670 | 749 | ||||||
Accrued expenses | 562 | 391 | ||||||
Payables to affiliates | 51 | 47 | ||||||
Deferred income taxes | 216 | 427 | ||||||
Mark-to-market derivative liabilities | 47 | 34 | ||||||
Other | 198 | 192 | ||||||
Total current liabilities | 1,747 | 1,843 | ||||||
Long-term debt | 3,675 | 3,676 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 3,616 | 3,318 | ||||||
Asset retirement obligations | 3,458 | 3,357 | ||||||
Non-pension postretirement benefit obligations | 756 | 692 | ||||||
Spent nuclear fuel obligation | 1,019 | 1,018 | ||||||
Payables to affiliates | 2,380 | 2,267 | ||||||
Mark-to-market derivative liabilities | 36 | 21 | ||||||
Payable for Zion Station decommissioning | 640 | 659 | ||||||
Other | 514 | 506 | ||||||
Total deferred credits and other liabilities | 12,419 | 11,838 | ||||||
Total liabilities | 17,841 | 17,357 | ||||||
Commitments and contingencies | ||||||||
Equity | ||||||||
Member’s equity | ||||||||
Membership interest | 3,526 | 3,526 | ||||||
Undistributed earnings | 3,571 | 2,633 | ||||||
Accumulated other comprehensive income, net | 690 | 1,013 | ||||||
Total member’s equity | 7,787 | 7,172 | ||||||
Noncontrolling interest | 5 | 5 | ||||||
Total equity | 7,792 | 7,177 | ||||||
Total liabilities and equity | $ | 25,633 | $ | 24,534 | ||||
See the Combined Notes to Consolidated Financial Statements
15
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
Member’s Equity | ||||||||||||||||||||
Accumulated | ||||||||||||||||||||
Other | ||||||||||||||||||||
Membership | Undistributed | Comprehensive | Noncontrolling | Total | ||||||||||||||||
(In millions) | Interest | Earnings | Income, net | Interest | Equity | |||||||||||||||
Balance, December 31, 2009 | $ | 3,464 | $ | 2,169 | $ | 1,157 | $ | 2 | $ | 6,792 | ||||||||||
Net income | — | 943 | — | — | 943 | |||||||||||||||
Allocation of tax benefit from member | 1 | — | — | — | 1 | |||||||||||||||
Distribution to member | — | (417 | ) | — | — | (417 | ) | |||||||||||||
Other comprehensive income, net of income taxes of $(1) | — | — | 6 | — | 6 | |||||||||||||||
Balance, June 30, 2010 | $ | 3,465 | $ | 2,695 | $ | 1,163 | $ | 2 | $ | 7,325 | ||||||||||
Member’s Equity | ||||||||||||||||||||
(In millions) | Membership Interest | Undistributed Earnings | Accumulated Other Comprehensive Income, net | Noncontrolling Interest | Total Equity | |||||||||||||||
Balance, December 31, 2010 | $ | 3,526 | $ | 2,633 | $ | 1,013 | $ | 5 | $ | 7,177 | ||||||||||
Net income | — | 938 | — | — | 938 | |||||||||||||||
Other comprehensive loss, net of income taxes of $212 | — | — | (323 | ) | — | (323 | ) | |||||||||||||
Balance, June 30, 2011 | $ | 3,526 | $ | 3,571 | $ | 690 | $ | 5 | $ | 7,792 | ||||||||||
See the Combined Notes to Consolidated Financial Statements
16
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(In millions) | 2010 | 2009 | 2010 | 2009 | ||||||||||||
Operating revenues | ||||||||||||||||
Operating revenues | $ | 1,499 | $ | 1,389 | $ | 2,913 | $ | 2,941 | ||||||||
Operating revenues from affiliates | — | — | 1 | 1 | ||||||||||||
Total operating revenues | 1,499 | 1,389 | 2,914 | 2,942 | ||||||||||||
Operating expenses | ||||||||||||||||
Purchased power | 516 | 368 | 900 | 812 | ||||||||||||
Purchased power from affiliate | 255 | 347 | 624 | 786 | ||||||||||||
Operating and maintenance | 240 | 224 | 360 | 433 | ||||||||||||
Operating and maintenance from affiliate | 36 | 46 | 75 | 89 | ||||||||||||
Operating and maintenance for regulatory required programs | 21 | 14 | 40 | 25 | ||||||||||||
Depreciation and amortization | 131 | 124 | 261 | 246 | ||||||||||||
Taxes other than income | 44 | 57 | 107 | 136 | ||||||||||||
Total operating expenses | 1,243 | 1,180 | 2,367 | 2,527 | ||||||||||||
Operating income | 256 | 209 | 547 | 415 | ||||||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (130 | ) | (72 | ) | (211 | ) | (152 | ) | ||||||||
Interest expense to affiliates, net | (4 | ) | (3 | ) | (7 | ) | (7 | ) | ||||||||
Other, net | 8 | 55 | 11 | 87 | ||||||||||||
Total other income and deductions | (126 | ) | (20 | ) | (207 | ) | (72 | ) | ||||||||
Income before income taxes | 130 | 189 | 340 | 343 | ||||||||||||
Income taxes | 121 | 73 | 215 | 113 | ||||||||||||
Net income | 9 | 116 | 125 | 230 | ||||||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||
Change in unrealized loss on cash flow hedges | (4 | ) | — | (4 | ) | — | ||||||||||
Change in unrealized gain on marketable securities | — | 7 | — | 5 | ||||||||||||
Other comprehensive income (loss) | (4 | ) | 7 | (4 | ) | 5 | ||||||||||
Comprehensive income | $ | 5 | $ | 123 | $ | 121 | $ | 235 | ||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(In millions) | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Operating revenues | ||||||||||||||||
Operating revenues | $ | 1,444 | $ | 1,499 | $ | 2,909 | $ | 2,913 | ||||||||
Operating revenues from affiliates | — | — | 1 | 1 | ||||||||||||
Total operating revenues | 1,444 | 1,499 | 2,910 | 2,914 | ||||||||||||
Operating expenses | ||||||||||||||||
Purchased power | 588 | 516 | 1,214 | 900 | ||||||||||||
Purchased power from affiliate | 128 | 255 | 291 | 624 | ||||||||||||
Operating and maintenance | 209 | 240 | 420 | 360 | ||||||||||||
Operating and maintenance from affiliate | 36 | 36 | 73 | 75 | ||||||||||||
Operating and maintenance for regulatory required programs | 23 | 21 | 41 | 40 | ||||||||||||
Depreciation and amortization | 136 | 131 | 270 | 261 | ||||||||||||
Taxes other than income | 70 | 44 | 147 | 107 | ||||||||||||
Total operating expenses | 1,190 | 1,243 | 2,456 | 2,367 | ||||||||||||
Operating income | 254 | 256 | 454 | 547 | ||||||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (82 | ) | (130 | ) | (164 | ) | (211 | ) | ||||||||
Interest expense to affiliates, net | (4 | ) | (4 | ) | (8 | ) | (7 | ) | ||||||||
Other, net | 4 | 8 | 8 | 11 | ||||||||||||
Total other income and deductions | (82 | ) | (126 | ) | (164 | ) | (207 | ) | ||||||||
Income before income taxes | 172 | 130 | 290 | 340 | ||||||||||||
Income taxes | 58 | 121 | 107 | 215 | ||||||||||||
Net income | 114 | 9 | 183 | 125 | ||||||||||||
Other comprehensive income, net of income taxes | ||||||||||||||||
Change in unrealized loss on cash flow hedges | — | (4 | ) | — | (4 | ) | ||||||||||
Other comprehensive loss | — | (4 | ) | — | (4 | ) | ||||||||||
Comprehensive income | $ | 114 | $ | 5 | $ | 183 | $ | 121 | ||||||||
See the Combined Notes to Consolidated Financial Statements
17
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended | ||||||||
June 30, | ||||||||
(In millions) | 2010 | 2009 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 125 | $ | 230 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 261 | 246 | ||||||
Deferred income taxes and amortization of investment tax credits | 11 | 142 | ||||||
Other non-cash operating activities | 60 | 159 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (156 | ) | 42 | |||||
Receivables from and payables to affiliates, net | (81 | ) | (31 | ) | ||||
Inventories | (2 | ) | (5 | ) | ||||
Accounts payable, accrued expenses and other current liabilities | 43 | (90 | ) | |||||
Counterparty collateral (posted) received, net | (118 | ) | 1 | |||||
Income taxes | 182 | (73 | ) | |||||
Pension and non-pension postretirement benefit contributions | (16 | ) | (6 | ) | ||||
Other assets and liabilities | 95 | (34 | ) | |||||
Net cash flows provided by operating activities | 404 | 581 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (453 | ) | (423 | ) | ||||
Other investing activities | 16 | 2 | ||||||
Net cash flows used in investing activities | (437 | ) | (421 | ) | ||||
Cash flows from financing activities | ||||||||
Changes in short-term debt | 134 | (15 | ) | |||||
Issuance of long-term debt | — | 191 | ||||||
Retirement of long-term debt | (1 | ) | (208 | ) | ||||
Dividends paid on common stock | (150 | ) | (120 | ) | ||||
Net cash flows used in financing activities | (17 | ) | (152 | ) | ||||
Increase (decrease) in cash and cash equivalents | (50 | ) | 8 | |||||
Cash and cash equivalents at beginning of period | 91 | 47 | ||||||
Cash and cash equivalents at end of period | $ | 41 | $ | 55 | ||||
Six Months Ended June 30, | ||||||||
(In millions) | 2011 | 2010 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 183 | $ | 125 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 270 | 261 | ||||||
Deferred income taxes and amortization of investment tax credits | 184 | 11 | ||||||
Other non-cash operating activities | 115 | 60 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (62 | ) | (156 | ) | ||||
Receivables from and payables to affiliates, net | (23 | ) | (81 | ) | ||||
Inventories | (7 | ) | (2 | ) | ||||
Accounts payable, accrued expenses and other current liabilities | (108 | ) | 43 | |||||
Counterparty collateral received (paid), net | 31 | (118 | ) | |||||
Income taxes | 321 | 182 | ||||||
Pension and non-pension postretirement benefit contributions | (871 | ) | (16 | ) | ||||
Other assets and liabilities | 38 | 95 | ||||||
Net cash flows provided by operating activities | 71 | 404 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (495 | ) | (453 | ) | ||||
Other investing activities | 22 | 16 | ||||||
Net cash flows used in investing activities | (473 | ) | (437 | ) | ||||
Cash flows from financing activities | ||||||||
Changes in short-term debt | — | 134 | ||||||
Issuance of long-term debt | 599 | — | ||||||
Retirement of long-term debt | (1 | ) | (1 | ) | ||||
Dividends paid on common stock | (150 | ) | (150 | ) | ||||
Other financing activities | (2 | ) | — | |||||
Net cash flows provided by (used in) financing activities | 446 | (17 | ) | |||||
Increase (Decrease) in cash and cash equivalents | 44 | (50 | ) | |||||
Cash and cash equivalents at beginning of period | 50 | 91 | ||||||
Cash and cash equivalents at end of period | $ | 94 | $ | 41 | ||||
See the Combined Notes to Consolidated Financial Statements
18
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, | December 31, | |||||||
(In millions) | 2010 | 2009 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 41 | $ | 91 | ||||
Restricted cash and cash equivalents | 3 | 2 | ||||||
Accounts receivable, net | ||||||||
Customer | 815 | 676 | ||||||
Other | 217 | 318 | ||||||
Inventories, net | 73 | 71 | ||||||
Regulatory assets | 397 | 358 | ||||||
Deferred income taxes | 56 | 39 | ||||||
Counterparty collateral deposited | 120 | — | ||||||
Other | 15 | 24 | ||||||
Total current assets | 1,737 | 1,579 | ||||||
Property, plant and equipment, net | 12,307 | 12,125 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 1,082 | 1,096 | ||||||
Investments | 24 | 28 | ||||||
Investments in affiliates | 6 | 6 | ||||||
Goodwill | 2,625 | 2,625 | ||||||
Receivables from affiliates | 1,800 | 1,920 | ||||||
Prepaid pension asset | 862 | 907 | ||||||
Other | 427 | 411 | ||||||
Total deferred debits and other assets | 6,826 | 6,993 | ||||||
Total assets | $ | 20,870 | $ | 20,697 | ||||
(In millions) | June 30, 2011 | December 31, 2010 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 94 | $ | 50 | ||||
Restricted cash | 3 | — | ||||||
Accounts receivable, net | ||||||||
Customer | 748 | 768 | ||||||
Other | 287 | 525 | ||||||
Inventories, net | 79 | 72 | ||||||
Deferred income taxes | 40 | 115 | ||||||
Counterparty collateral deposited | 125 | 153 | ||||||
Regulatory assets | 505 | 456 | ||||||
Other | 20 | 12 | ||||||
Total current assets | 1,901 | 2,151 | ||||||
Property, plant and equipment, net | 12,824 | 12,578 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 822 | 947 | ||||||
Investments | 22 | 23 | ||||||
Investments in affiliates | 6 | 6 | ||||||
Goodwill | 2,625 | 2,625 | ||||||
Receivables from affiliates | 1,981 | 1,895 | ||||||
Mark-to-market derivative assets | — | 4 | ||||||
Prepaid pension asset | 1,856 | 1,039 | ||||||
Other | 311 | 384 | ||||||
Total deferred debits and other assets | 7,623 | 6,923 | ||||||
Total assets | $ | 22,348 | $ | 21,652 | ||||
See the Combined Notes to Consolidated Financial Statements
19
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, | December 31, | |||||||
(In millions) | 2010 | 2009 | ||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term borrowings | $ | 289 | $ | 155 | ||||
Long-term debt due within one year | 213 | 213 | ||||||
Accounts payable | 329 | 274 | ||||||
Accrued expenses | 265 | 282 | ||||||
Payables to affiliates | 72 | 177 | ||||||
Customer deposits | 131 | 131 | ||||||
Mark-to-market derivative liability with affiliate | 383 | 302 | ||||||
Other | 70 | 63 | ||||||
Total current liabilities | 1,752 | 1,597 | ||||||
Long-term debt | 4,499 | 4,498 | ||||||
Long-term debt to financing trust | 206 | 206 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 2,675 | 2,648 | ||||||
Asset retirement obligations | 96 | 95 | ||||||
Non-pension postretirement benefits obligations | 285 | 241 | ||||||
Regulatory liabilities | 3,045 | 3,145 | ||||||
Mark-to-market derivative liability with affiliate | 627 | 669 | ||||||
Other | 832 | 716 | ||||||
Total deferred credits and other liabilities | 7,560 | 7,514 | ||||||
Total liabilities | 14,017 | 13,815 | ||||||
Commitments and contingencies | ||||||||
Shareholders’ equity | ||||||||
Common stock | 1,588 | 1,588 | ||||||
Other paid-in capital | 4,990 | 4,990 | ||||||
Retained earnings | 279 | 304 | ||||||
Accumulated other comprehensive loss, net | (4 | ) | — | |||||
�� | ||||||||
Total shareholders’ equity | 6,853 | 6,882 | ||||||
Total liabilities and shareholders’ equity | $ | 20,870 | $ | 20,697 | ||||
(In millions) | June 30, 2011 | December 31, 2010 | ||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Long-term debt due within one year | 796 | 347 | ||||||
Accounts payable | 303 | 332 | ||||||
Accrued expenses | 260 | 366 | ||||||
Payables to affiliates | 374 | 398 | ||||||
Customer deposits | 133 | 130 | ||||||
Regulatory liabilities | 23 | 19 | ||||||
Mark-to-market derivative liability with affiliate | 412 | 450 | ||||||
Other | 107 | 92 | ||||||
Total current liabilities | 2,408 | 2,134 | ||||||
Long-term debt | 4,805 | 4,654 | ||||||
Long-term debt to financing trust | 206 | 206 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 3,461 | 3,308 | ||||||
Asset retirement obligations | 106 | 105 | ||||||
Non-pension postretirement benefits obligations | 324 | 271 | ||||||
Regulatory liabilities | 3,250 | 3,137 | ||||||
Mark-to-market derivative liability | 30 | — | �� | |||||
Mark-to-market derivative liability with affiliate | 345 | 525 | ||||||
Other | 470 | 402 | ||||||
Total deferred credits and other liabilities | 7,986 | 7,748 | ||||||
Total liabilities | 15,405 | 14,742 | ||||||
Commitments and contingencies | ||||||||
Shareholders’ equity | ||||||||
Common stock | 1,588 | 1,588 | ||||||
Other paid-in capital | 4,992 | 4,992 | ||||||
Retained earnings | 364 | 331 | ||||||
Accumulated other comprehensive loss, net | (1 | ) | (1 | ) | ||||
Total shareholders’ equity | 6,943 | 6,910 | ||||||
Total liabilities and shareholders’ equity | $ | 22,348 | $ | 21,652 | ||||
See the Combined Notes to Consolidated Financial Statements
20
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Accumulated | ||||||||||||||||||||||||
Retained | Other | Total | ||||||||||||||||||||||
Common | Other Paid- | Retained Deficit | Earnings | Comprehensive | Shareholders’ | |||||||||||||||||||
(In millions) | Stock | In Capital | Unappropriated | Appropriated | Loss, net | Equity | ||||||||||||||||||
Balance, December 31, 2009 | $ | 1,588 | $ | 4,990 | $ | (1,639 | ) | $ | 1,943 | $ | — | $ | 6,882 | |||||||||||
Net income | — | — | 125 | — | — | 125 | ||||||||||||||||||
Appropriation of retained earnings for future dividends | — | — | (187 | ) | 187 | — | — | |||||||||||||||||
Common stock dividends | — | — | — | (150 | ) | — | (150 | ) | ||||||||||||||||
Other comprehensive income, net of income taxes of $(2) | — | — | — | — | (4 | ) | (4 | ) | ||||||||||||||||
Balance, June 30, 2010 | $ | 1,588 | $ | 4,990 | $ | (1,701 | ) | $ | 1,980 | $ | (4 | ) | $ | 6,853 | ||||||||||
(In millions) | Common Stock | Other Paid-In Capital | Retained Deficit Unappropriated | Retained Earnings Appropriated | Accumulated Other Comprehensive Loss, net | Total Shareholders’ Equity | ||||||||||||||||||
Balance, December 31, 2010 | $ | 1,588 | $ | 4,992 | $ | (1,639 | ) | $ | 1,970 | $ | (1 | ) | $ | 6,910 | ||||||||||
Net income | — | — | 183 | — | — | 183 | ||||||||||||||||||
Appropriation of retained earnings for future dividends | — | — | (183 | ) | 183 | — | — | |||||||||||||||||
Common stock dividends | — | — | — | (150 | ) | — | (150 | ) | ||||||||||||||||
Balance, June 30, 2011 | $ | 1,588 | $ | 4,992 | $ | (1,639 | ) | $ | 2,003 | $ | (1 | ) | $ | 6,943 | ||||||||||
See the Combined Notes to Consolidated Financial Statements
21
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(In millions) | 2010 | 2009 | 2010 | 2009 | ||||||||||||
Operating revenues | ||||||||||||||||
Operating revenues | $ | 1,268 | $ | 1,201 | $ | 2,721 | $ | 2,712 | ||||||||
Operating revenues from affiliates | 1 | 3 | 3 | 6 | ||||||||||||
Total operating revenues | 1,269 | 1,204 | 2,724 | 2,718 | ||||||||||||
Operating expenses | ||||||||||||||||
Purchased power | 69 | 67 | 135 | 132 | ||||||||||||
Purchased power from affiliate | 466 | 480 | 924 | 984 | ||||||||||||
Fuel | 44 | 55 | 255 | 321 | ||||||||||||
Operating and maintenance | 127 | 123 | 286 | 276 | ||||||||||||
Operating and maintenance from affiliates | 23 | 26 | 45 | 51 | ||||||||||||
Operating and maintenance for regulatory required programs | 13 | — | 21 | — | ||||||||||||
Depreciation and amortization | 268 | 230 | 533 | 455 | ||||||||||||
Taxes other than income | 77 | 69 | 150 | 135 | ||||||||||||
Total operating expenses | 1,087 | 1,050 | 2,349 | 2,354 | ||||||||||||
Operating income | 182 | 154 | 375 | 364 | ||||||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (74 | ) | (32 | ) | (116 | ) | (61 | ) | ||||||||
Interest expense to affiliates, net | (3 | ) | (17 | ) | (6 | ) | (38 | ) | ||||||||
Loss in equity method investments | — | (6 | ) | — | (12 | ) | ||||||||||
Other, net | (1 | ) | 3 | 4 | 6 | |||||||||||
Total other income and deductions | (78 | ) | (52 | ) | (118 | ) | (105 | ) | ||||||||
Income before income taxes | 104 | 102 | 257 | 259 | ||||||||||||
Income taxes | 29 | 31 | 81 | 76 | ||||||||||||
Net income | 75 | 71 | 176 | 183 | ||||||||||||
Preferred security dividends | 1 | 1 | 2 | 2 | ||||||||||||
Net income on common stock | 74 | 70 | 174 | 181 | ||||||||||||
Comprehensive income, net of income taxes | ||||||||||||||||
Net income | 75 | 71 | 176 | 183 | ||||||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||
Amortization of realized loss on settled cash flow swaps | (1 | ) | — | (1 | ) | — | ||||||||||
Change in unrealized gain on marketable securities | — | 1 | — | — | ||||||||||||
Other comprehensive income (loss) | (1 | ) | 1 | (1 | ) | — | ||||||||||
Comprehensive income | $ | 74 | $ | 72 | $ | 175 | $ | 183 | ||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(In millions) | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Operating revenues | ||||||||||||||||
Operating revenues | $ | 842 | $ | 1,268 | $ | 1,994 | $ | 2,721 | ||||||||
Operating revenues from affiliates | — | 1 | 2 | 3 | ||||||||||||
Total operating revenues | 842 | 1,269 | 1,996 | 2,724 | ||||||||||||
Operating expenses | ||||||||||||||||
Purchased power | 253 | 69 | 563 | 135 | ||||||||||||
Purchased power from affiliate | 115 | 466 | 257 | 924 | ||||||||||||
Fuel | 40 | 44 | 222 | 255 | ||||||||||||
Operating and maintenance | 132 | 127 | 296 | 286 | ||||||||||||
Operating and maintenance from affiliates | 22 | 23 | 44 | 45 | ||||||||||||
Operating and maintenance for regulatory required programs | 18 | 13 | 38 | 21 | ||||||||||||
Depreciation and amortization | 50 | 268 | 98 | 533 | ||||||||||||
Taxes other than income | 51 | 77 | 106 | 150 | ||||||||||||
Total operating expenses | 681 | 1,087 | 1,624 | 2,349 | ||||||||||||
Operating income | 161 | 182 | 372 | 375 | ||||||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (31 | ) | (74 | ) | (62 | ) | (116 | ) | ||||||||
Interest expense to affiliates, net | (3 | ) | (3 | ) | (6 | ) | (6 | ) | ||||||||
Other, net | 3 | (1 | ) | 8 | 4 | |||||||||||
Total other income and deductions | (31 | ) | (78 | ) | (60 | ) | (118 | ) | ||||||||
Income before income taxes | 130 | 104 | 312 | 257 | ||||||||||||
Income taxes | 47 | 29 | 102 | 81 | ||||||||||||
Net income | 83 | 75 | 210 | 176 | ||||||||||||
Preferred security dividends | 1 | 1 | 2 | 2 | ||||||||||||
Net income on common stock | 82 | 74 | 208 | 174 | ||||||||||||
Comprehensive income, net of income taxes | ||||||||||||||||
Net income | 83 | 75 | 210 | 176 | ||||||||||||
Other comprehensive loss, net of income taxes | ||||||||||||||||
Amortization of realized gain on settled cash flow swaps | — | (1 | ) | — | (1 | ) | ||||||||||
Other comprehensive loss | — | (1 | ) | — | (1 | ) | ||||||||||
Comprehensive income | $ | 83 | $ | 74 | $ | 210 | $ | 175 | ||||||||
See the Combined Notes to Consolidated Financial Statements
22
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended | ||||||||
June 30, | ||||||||
(In millions) | 2010 | 2009 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 176 | $ | 183 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 533 | 455 | ||||||
Deferred income taxes and amortization of investment tax credits | (388 | ) | (102 | ) | ||||
Other non-cash operating activities | 44 | 83 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (75 | ) | 69 | |||||
Receivables from and payables to affiliates, net | 27 | 64 | ||||||
Inventories | 30 | 79 | ||||||
Accounts payable, accrued expenses and other current liabilities | (21 | ) | (154 | ) | ||||
Income taxes | 323 | 51 | ||||||
Pension and non-pension postretirement benefit contributions | (20 | ) | (16 | ) | ||||
Other assets and liabilities | (74 | ) | (128 | ) | ||||
Net cash flows provided by operating activities | 555 | 584 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (218 | ) | (179 | ) | ||||
Changes in Exelon intercompany money pool | — | (74 | ) | |||||
Change in restricted cash | (14 | ) | 2 | |||||
Other investing activities | 10 | 1 | ||||||
Net cash flows used in investing activities | (222 | ) | (250 | ) | ||||
Cash flows from financing activities | ||||||||
Changes in short-term debt | — | (95 | ) | |||||
Issuance of long-term debt | — | 248 | ||||||
Retirement of long-term debt of variable interest entity | (402 | ) | — | |||||
Retirement of long-term debt to PECO Energy Transition Trust | — | (330 | ) | |||||
Dividends paid on common stock | (115 | ) | (154 | ) | ||||
Dividends paid on preferred securities | (2 | ) | (2 | ) | ||||
Repayment of receivable from parent | 90 | 160 | ||||||
Net cash flows used in financing activities | (429 | ) | (173 | ) | ||||
Increase (decrease) in cash and cash equivalents | (96 | ) | 161 | |||||
Cash and cash equivalents at beginning of period | 303 | 39 | ||||||
Cash and cash equivalents at end of period | $ | 207 | $ | 200 | ||||
Six Months Ended June 30, | ||||||||
(In millions) | 2011 | 2010 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 210 | $ | 176 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 98 | 533 | ||||||
Deferred income taxes and amortization of investment tax credits | 91 | (388 | ) | |||||
Other non-cash operating activities | 44 | 44 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 221 | (75 | ) | |||||
Receivables from and payables to affiliates, net | (218 | ) | 27 | |||||
Inventories | 29 | 30 | ||||||
Accounts payable, accrued expenses and other current liabilities | (11 | ) | (21 | ) | ||||
Income taxes | 113 | 323 | ||||||
Pension and non-pension postretirement benefit contributions | (110 | ) | (20 | ) | ||||
Other assets and liabilities | (108 | ) | (74 | ) | ||||
Net cash flows provided by operating activities | 359 | 555 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (209 | ) | (218 | ) | ||||
Changes in Exelon intercompany money pool | (171 | ) | — | |||||
Change in restricted cash | (2 | ) | (14 | ) | ||||
Other investing activities | 11 | 10 | ||||||
Net cash flows used in investing activities | (371 | ) | (222 | ) | ||||
Cash flows from financing activities | ||||||||
Retirement of long-term debt of variable interest entity | — | (402 | ) | |||||
Dividends paid on common stock | (184 | ) | (115 | ) | ||||
Dividends paid on preferred securities | (2 | ) | (2 | ) | ||||
Repayment of receivable from parent | — | 90 | ||||||
Other financing activities | (5 | ) | — | |||||
Net cash flows used in financing activities | (191 | ) | (429 | ) | ||||
Decrease in cash and cash equivalents | (203 | ) | (96 | ) | ||||
Cash and cash equivalents at beginning of period | 522 | 303 | ||||||
Cash and cash equivalents at end of period | $ | 319 | $ | 207 | ||||
See the Combined Notes to Consolidated Financial Statements
23
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, | December 31, | |||||||
(In millions) | 2010 | 2009 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 207 | $ | 303 | ||||
Restricted cash and cash equivalents | 2 | 1 | ||||||
Restricted cash and cash equivalents of variable interest entity | 426 | — | ||||||
Accounts receivable, net | ||||||||
Customer ($366 gross accounts receivable pledged as collateral as of June 30, 2010) | 641 | 392 | ||||||
Other | 74 | 120 | ||||||
Inventories, net | ||||||||
Fossil fuel | 65 | 96 | ||||||
Materials and supplies | 19 | 18 | ||||||
Deferred income taxes | 63 | 65 | ||||||
Prepaid utility taxes | 112 | — | ||||||
Other | 26 | 11 | ||||||
Total current assets | 1,635 | 1,006 | ||||||
Property, plant and equipment, net | 5,421 | 5,297 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 1,403 | 1,834 | ||||||
Investments | 17 | 18 | ||||||
Investments in affiliates | 8 | 13 | ||||||
Receivable from affiliates | 272 | 311 | ||||||
Prepaid pension asset | 237 | 225 | ||||||
Other | 78 | 315 | ||||||
Total deferred debits and other assets | 2,015 | 2,716 | ||||||
Total assets | $ | 9,071 | $ | 9,019 | ||||
(In millions) | June 30, 2011 | December 31, 2010 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 319 | $ | 522 | ||||
Restricted cash and cash equivalents | 2 | — | ||||||
Accounts receivable, net | ||||||||
Customer ($309 and $346 gross accounts receivable pledged as collateral as of June 30, 2011 and December 31, 2010, respectively) | 435 | 695 | ||||||
Other | 199 | 277 | ||||||
Inventories, net | ||||||||
Fossil fuel | 57 | 87 | ||||||
Materials and supplies | 19 | 18 | ||||||
Deferred income taxes | 41 | 41 | ||||||
Receivable from Exelon intercompany money pool | 171 | — | ||||||
Prepaid utility taxes | 92 | — | ||||||
Regulatory assets | 34 | 9 | ||||||
Other | 35 | 21 | ||||||
Total current assets | 1,404 | 1,670 | ||||||
Property, plant and equipment, net | 5,730 | 5,620 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 1,010 | 968 | ||||||
Investments | 22 | 20 | ||||||
Investments in affiliates | 8 | 8 | ||||||
Receivable from affiliates | 401 | 375 | ||||||
Prepaid pension asset | 386 | 281 | ||||||
Other | 35 | 43 | ||||||
Total deferred debits and other assets | 1,862 | 1,695 | ||||||
Total assets | $ | 8,996 | $ | 8,985 | ||||
See the Combined Notes to Consolidated Financial Statements
24
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, | December 31, | |||||||
(In millions) | 2010 | 2009 | ||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term notes payable — accounts receivable agreement | $ | 225 | $ | — | ||||
Long-term debt of variable interest entity due within one year | 404 | — | ||||||
Long-term debt to PECO Energy Transition Trust due within one year | — | 415 | ||||||
Accounts payable | 147 | 164 | ||||||
Accrued expenses | 132 | 74 | ||||||
Payables to affiliates | 216 | 189 | ||||||
Customer deposits | 65 | 65 | ||||||
Mark-to-market derivative liabilities | 2 | — | ||||||
Mark-to-market derivative liabilities with affiliate | 3 | — | ||||||
Other | 46 | 32 | ||||||
Total current liabilities | 1,240 | 939 | ||||||
Long-term debt | 2,221 | 2,221 | ||||||
Long-term debt to financing trusts | 184 | 184 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 1,857 | 2,241 | ||||||
Asset retirement obligations | 25 | 24 | ||||||
Non-pension postretirement benefits obligations | 311 | 296 | ||||||
Regulatory liabilities | 299 | 317 | ||||||
Mark-to-market derivative liabilities | 2 | 2 | ||||||
Mark-to-market derivative liabilities with affiliate | 2 | 2 | ||||||
Other | 130 | 141 | ||||||
Total deferred credits and other liabilities | 2,626 | 3,023 | ||||||
Total liabilities | 6,271 | 6,367 | ||||||
Commitments and contingencies | ||||||||
Preferred securities | 87 | 87 | ||||||
Shareholders’ equity | ||||||||
Common stock | 2,318 | 2,318 | ||||||
Receivable from parent | (90 | ) | (180 | ) | ||||
Retained earnings | 485 | 426 | ||||||
Accumulated other comprehensive income, net | — | 1 | ||||||
Total shareholders’ equity | 2,713 | 2,565 | ||||||
Total liabilities and shareholders’ equity | $ | 9,071 | $ | 9,019 | ||||
(In millions) | June 30, 2011 | December 31, 2010 | ||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term notes payable — accounts receivable agreement | $ | 225 | $ | 225 | ||||
Long-term debt due within one year | 250 | 250 | ||||||
Accounts payable | 244 | 201 | ||||||
Accrued expenses | 77 | 95 | ||||||
Payables to affiliates | 57 | 275 | ||||||
Customer deposits | 55 | 65 | ||||||
Regulatory liabilities | 40 | 25 | ||||||
Mark-to-market derivative liabilities | 2 | 4 | ||||||
Mark-to-market derivative liabilities with affiliate | 2 | 5 | ||||||
Other | 22 | 18 | ||||||
Total current liabilities | 974 | 1,163 | ||||||
Long-term debt | 1,972 | 1,972 | ||||||
Long-term debt to financing trusts | 184 | 184 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 1,947 | 1,823 | ||||||
Asset retirement obligations | 33 | 32 | ||||||
Non-pension postretirement benefits obligations | 304 | 292 | ||||||
Regulatory liabilities | 457 | 418 | ||||||
Other | 131 | 131 | ||||||
Total deferred credits and other liabilities | 2,872 | 2,696 | ||||||
Total liabilities | 6,002 | 6,015 | ||||||
Commitments and contingencies | ||||||||
Preferred securities | 87 | 87 | ||||||
Shareholders’ equity | ||||||||
Common stock | 2,361 | 2,361 | ||||||
Retained earnings | 546 | 522 | ||||||
Total shareholders’ equity | 2,907 | 2,883 | ||||||
Total liabilities and shareholders’ equity | $ | 8,996 | $ | 8,985 | ||||
See the Combined Notes to Consolidated Financial Statements
25
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Accumulated | ||||||||||||||||||||
Other | Total | |||||||||||||||||||
Common | Receivable | Retained | Comprehensive | Shareholders’ | ||||||||||||||||
(In millions) | Stock | from Parent | Earnings | Income, net | Equity | |||||||||||||||
Balance, December 31, 2009 | $ | 2,318 | $ | (180 | ) | $ | 426 | $ | 1 | $ | 2,565 | |||||||||
Net income | — | — | 176 | — | 176 | |||||||||||||||
Common stock dividends | — | — | (115 | ) | — | (115 | ) | |||||||||||||
Preferred security dividends | — | — | (2 | ) | — | (2 | ) | |||||||||||||
Repayment of receivable from parent | — | 90 | — | — | 90 | |||||||||||||||
Other comprehensive loss, net of income taxes of $0 | — | — | — | (1 | ) | (1 | ) | |||||||||||||
Balance, June 30, 2010 | $ | 2,318 | $ | (90 | ) | $ | 485 | $ | — | $ | 2,713 | |||||||||
(In millions) | Common Stock | Retained Earnings | Total Shareholders’ Equity | |||||||||
Balance, December 31, 2010 | $ | 2,361 | $ | 522 | $ | 2,883 | ||||||
Net income | — | 210 | 210 | |||||||||
Common stock dividends | — | (184 | ) | (184 | ) | |||||||
Preferred security dividends | — | (2 | ) | (2 | ) | |||||||
Balance, June 30, 2011 | $ | 2,361 | $ | 546 | $ | 2,907 | ||||||
See the Combined Notes to Consolidated Financial Statements
26
(Dollars in millions, except per share data, unless otherwise noted)
Exelon is a utility services holding company engaged, through its principal subsidiaries, in the energy generation and energy delivery businesses. The generation business consists of the electric generating facilities, the wholesale energy marketing operations and competitive retail supply operations of Generation. The energy delivery businesses include the purchase and regulated retail sale of electricity and the provision of distribution and transmission services by ComEd in northern Illinois, including the City of Chicago, and by PECO in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance type costs that cannot be directly assigned are allocated based on a Modified Massachusetts formula, which is a method that utilizes a combination of gross revenues, total assets, and direct labor costs for the allocation base. The results of Exelon’s corporate operations are presented as “Other” within the notesCombined Notes to the consolidated financial statementsConsolidated Financial Statements and include intercompany eliminations unless otherwise disclosed.
Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for Exelon SHC, LLC, of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon and is eliminated in Exelon’s consolidated financial statements, ComEd, of which Exelon owns more than 99%, and PECO, of which Exelon owns 100% of the common stock but none of PECO’s preferred securities. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at June 30, 2010,2011, as equity, and PECO’s preferred securities as preferred securities of subsidiary in its Consolidated Financial Statements.
Generation owns 100% of all of its significant consolidated financial statements.
Exelon’s Consolidated Financial Statements include the accounts of entities in which Exelon has a controlling financial interest, other than certain financing trusts of ComEd and PECO, and Generation’s and PECO’s proportionate interests in jointly owned electric utility property, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Investments and joint ventures, in which Exelon does not have a controlling financial interest and certain financing trusts of ComEd and PECO, are accounted for under the equity or cost method of accounting.
Each of Generation’s, ComEd’s and PECO’s consolidated financial statementsConsolidated Financial Statements includes the accounts of theirits subsidiaries. All intercompany transactions have been eliminated.
The accompanying consolidated financial statements as of June 30, 20102011 and 20092010 and for the three and six months then ended are unaudited but, in the opinion of the management of each of Exelon, Generation, ComEd and PECO, include all adjustments that are considered necessary for a fair presentation of its respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 20092010 Consolidated Balance Sheets were taken from audited financial statements. Certain prior year amounts in Exelon’s Generation’s and ComEd’sGeneration’s Consolidated Statements of Cash Flows and in
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon’s, ComEd’s and PECO’s Consolidated Balance Sheets have been reclassified between line items for comparative purposes. The reclassifications did not affect Exelon’s, Generation’sthe Registrants’ net income or ComEd’s cash flows from operating activities or ComEd’sactivities. See Note 14 — Supplemental Financial Information for further discussion of the reclassifications to Exelon’s and PECO’s financial position.Generation’s Consolidated Statements of Cash Flows. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These notes should be read in conjunction with the Notes to Consolidated Financial Statements of Exelon, Generation, ComEd and PECO included in ITEM 8 of their 2009 Annual Report on2010 Form 10-K.
27
28
the Registrants’ VIEs, see Note 1 of the 2010 Form 10-K.
29
There were no recently issued accounting standards:
The following recently issued accounting standard isstandards are not yet required to be reflected in the combined consolidated financial statements of the Registrants:
Revenue Arrangements with Multiple DeliverablesFair Value Measurements
In October 2009,May 2011, the FASB issued authoritative guidance that amendsamending existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist,measuring fair value and provides guidance for allocating and recognizing revenue based on those separate deliverables.disclosing information about fair value measurements. The guidance is expectedFASB indicated that it generally does not intend the amendments to result in more multiple-deliverable arrangements being separable thana change to current accounting. Required disclosures are expanded under current guidance. Thisthe new guidance, is effectiveespecially for fair value measurements that are categorized within Level 3 of the Registrants beginning on January 1, 2011fair value hierarchy, for which quantitative information about the unobservable inputs, the valuation processes used by the entity, and the sensitivity of the measurement to the unobservable inputs will be required. Entities will also be required to disclose the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be applied prospectively to new or significantly modified revenue arrangements.disclosed. The Registrants are currently assessing the effects this guidance may have on their consolidated financial statements.
The guidance is effective for the Registrants for periods beginning after December 15, 2011 and is required to be applied prospectively.
30
(Dollars in millions, except per share data, unless otherwise noted)
Regulatory and Legislative Proceedings (Exelon, Generation, ComEd and PECO)
Except for the matters noted below, the disclosures set forth in Note 2 of the 20092010 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.
Illinois Regulatory Matters
Illinois Settlement Agreement (Exelon, Generation and ComEd).Various Illinois electric utilities, their affiliates and generatorsAppeal of electricity in Illinois agreed to contribute approximately $1 billion over a period of four years ending in 2010 to programs to provide rate relief to Illinois electricity customers and funding for the IPA, created as a result of the Illinois Settlement Legislation. Generation recognized net costs from its contributions pursuant to the Illinois Settlement Legislation of $7 million and $9 million for the three and six months ended June 30, 2010 and $30 million and $63 million for the three and six months ended June 30, 2009, respectively, in its Consolidated Statements of Operations. ComEd’s net costs from its contributions pursuant to the Illinois Settlement Legislation were $0 and $1 million for the three and six months ended June 30, 2010, respectively, and $2 million and $3 million for the three and six months ended June 30, 2009, respectively.
The Court held the ICC abused its discretion in not reducing ComEd’s rate base to account for an additional 18 months of accumulated depreciation while including post-test year pro forma plant additions through that period (the same position ComEd took in its 2010 electric distribution rate case (2010 Rate Case) discussed below). The Court’s ruling may trigger a refund obligation. The ICC will ultimately be required to set a just and reasonable rate that will determine the amount of any refund. The impact on ComEd’s rates and any associated refund obligation should be prospective from no earlier than the date of the Court’s ruling on September 30, 2010. ComEd continued to bill rates as established under the ICC’s order in the 2007 Rate Case, until June 1, 2011 when the rates set in the 2010 Rate Case became effective. ComEd has recognized for accounting purposes its estimate of any refund obligation, subject to true-up when the ICC establishes a new rate. An interest charge may accrue on any refund amount. ComEd recorded an estimated refund obligation of $55 million and $22 million related to the post-test year accumulated depreciation and AMI/Customer Applications pilot program issues as of June 30, 2011 and December 31, 2010, respectively.
The Court also reversed the ICC’s approval of ComEd’s Rider SMP, a program that authorized the installation of 131,000 smart meters in the Chicago area. As of June 30, 2011, ComEd had installed the majority of the meters authorized under this program. The Court held that the ICC’s approval of Rider SMP constituted illegal single-issue ratemaking. The Court’s decision prescribes a new, more stringent standard for cost recovery riders not specifically authorized by statute. Such riders would be allowed only if: (1) the pass-through cost is imposed by an “external circumstance” and is unexpected, volatile, or fluctuating; and (2) recovery via rider does not change other expenses or increase utility income. As a result of the Court’s ruling on Rider SMP, ComEd also recorded a $4 million (pre-tax) write-off of regulatory assets associated with operating and maintenance costs that were originally allowable under Rider SMP, as the costs can no longer be recovered from customers through Rider SMP. ComEd does not believe any of its other riders are affected by the Court’s ruling.
Subsequent to the Court’s ruling, ComEd filed a request with the ICC to allow it to request recovery, through inclusion in the 2010 Rate Case, of operation and maintenance costs that would have been recovered through the rider, as well as carrying costs associated with capital investment in the ICC-approved AMI/Customer Applications pilot program. The unrecovered Rider SMP pilot program costs had already been requested in rate base in the 2010 Rate Case. On December 2, 2010, the ICC approved ComEd’s request. The investment and the pilot program costs were approved in the 2010 Rate Case proceeding.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
2010 Illinois Electric Distribution Rate Case (Exelon and ComEd). On June 30, 2010, ComEd requested ICC approval for an increase of $396 million to its netannual delivery services revenue requirement. This request was subsequently reduced to $343 million to account for recent changes in tax law, corrections, acceptance of limited adjustments proposed by certain parties and the amounts expected to be recovered in the AMI pilot program tariff discussed above. The request to increase the annual revenue requirement for electric distributionwas to allow ComEd to continue modernizing its electric delivery system and recover the costs of substantial investments made since theits last rate filing in 2007. The requested increase also reflectsreflected increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The original requested rate of return on common equity iswas 11.5%. The requested increase in electric distribution rates would increase the average residential customer’s monthly electric bill by approximately 7%. In addition, ComEd is requestingrequested future recovery of certain amounts that were previously recorded as expense. Ifexpense that request is approved,would allow ComEd would reverse the previously expensed costs and establish regulatory assets with amortization over the period during which rate recovery is allowed. As a result, ComEd wouldto recognize a one-time benefit of up to $39$40 million (pre-tax) to reverse the prior charges.. The requested increase also includesincluded $22 million for increased uncollectible accounts expense. If the rate request is approved,expense, which would increase the threshold for determining over/under recoveries under ComEd’s uncollectible accounts tariff would be increasedtariff.
On May 24, 2011, the ICC issued an order in ComEd’s 2010 rate case, which became effective on June 1, 2011. The order approved a $143 million increase to ComEd’s annual delivery services revenue requirement and a 10.5% rate of return on common equity. As expected, the ICC followed the Court’s position on the post-test year accumulated depreciation issue. The order allows ComEd to establish or reestablish a net amount of approximately $40 million of previously expensed plant balances or new regulatory assets which is reflected as a reduction in operating and maintenance expense and income tax expense for the three and six months ended June 30, 2011. The order also affirmed the current regulatory asset for severance costs which was challenged by $22 million.an intervener in the 2010 Rate Case. The new electric distribution rates would take effect no later than June 2011.order has been appealed to the Court by several parties, including ComEd. ComEd cannot predict how muchthe results of these appeals.
Alternative Regulation Pilot Program (Exelon and ComEd). On August 31, 2010, ComEd filed with the ICC an alternative regulation pilot proposal as a companion proposal to its 2010 Rate Case under a provision of the requested electric distributionIllinois Public Utilities Act that contemplates an alternative regulatory structure. Rather than employing the traditional rate increasesetting process in which the utility seeks recovery of costs already incurred, the proposal would have brought utilities, stakeholders, and the ICC may approve.
together to develop, review and approve ongoing investment programs before those investments are made. The ICC did not approve ComEd’s alternative regulation pilot proposal.
31
(Dollars in millions, except per share data, unless otherwise noted)
The Illinois Energy Infrastructure Modernization Act (SB 1652), a prior version of which was originally introduced as HB 14, was passed by the Illinois General Assembly on May 31, 2011. SB 1652 would apply to electric utilities in Illinois on an opt-in basis. SB 1652 provides greater certainty related to the recovery of costs by a utility through a pre-established formula, which would still allow the ICC and interveners the opportunity to review the prudence and reasonableness of costs. If the legislation were to be enacted, ComEd would anticipate filing annual electric distribution formula rate cases and investing an additional $2.6 billion in capital expenditures over the next ten years to modernize its system and implement smart grid technology, including improvements to cyber security. These investments would be incremental to ComEd’s historical level of capital expenditures. SB 1652 also contains a provision for the IPA to complete a procurement event for energy requirements for the June 2013 through May 2017 period. If SB 1652 is enacted, the procurement event must take place within 120 days of the effective date of the legislation.
The bill remains in the Illinois Senate on a motion filed by the President of the Senate. When it is ultimately presented to the Governor, he has sixty days to decide on the bill; however, he has indicated that he may veto it. If approved in its current form, ComEd expects that it would begin to achieve closer to its allowed return on equity, which would have a material positive impact on ComEd’s net income as early as 2011. ComEd’s commitments in the bill associated with incremental capital expenditures would result in significant cash outflows beginning in 2012. ComEd cannot predict the eventual outcome of SB 1652 resulting from the Governor’s decision or subsequent actions taken by the Illinois General Assembly. To the extent that the bill is not enacted as currently written or in a comparable form, ComEd will seek alternative methods to achieve reasonable earned returns on equity, which would include additional electric distribution rate case filings with the ICC.
Illinois Legislation for Recovery of Uncollectible Accounts (Exelon and ComEd).In 2009, comprehensive legislation was enacted into law in Illinois providing public utility companies with On February 2, 2010, the abilityICC issued an order adopting tariffs for ComEd to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and amounts collected in rates annually through a rider mechanism, starting with 2008 and prospectively. On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs filed in accordance with the legislation, with minor modifications.annually. As a result of thethat ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense in the first quarter of 2010 for the cumulative under-collections in 2008 and 2009. Recovery of the regulatory asset associated with 2008 and 2009 activities will take place over an approximate 14-month time frame which began in April 2010. The recovery or refund of the difference in the uncollectible accounts expense applicable to the years starting with January 1, 2010, will take place over a 12-month time frame beginning in June of the following year. In addition, ComEd recorded a one-time charge of $10 million to operating and maintenance expense in the first quarter of 2010 for a contribution to the Supplemental Low-Income Energy Assistance Fund as required by the legislation. The fundwhich is used to assist low-income residential customers.
Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Since June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. In order to fulfill a requirement of the Illinois Settlement Legislation, ComEd hedged the price of a significant portion of energy purchased in the spot market with a five-year variable-to-fixed financial swap contract with Generation that expires on May 31, 2013. On December 21, 2010, the ICC approved the IPA’s procurement plan covering the period June 2011 through May 2016. As of June 30, 2011, ComEd has completed the ICC-approved procurement process for its energy requirements through May 2012 as well as a portion of its requirements for each of the years ending in May 2013 and May 2014.
The Illinois Settlement Legislation requires ComEd to purchase an increasing percentage of its electricity requirements from renewable energy resources. On December 17, 2010, ComEd entered into 20-year contracts with several unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. The long term renewables purchased will count towards satisfying ComEd’s obligation under the state’s RPS and all associated costs will be recoverable from customers. As of June 30, 2011, ComEd has completed the ICC-approved procurement process for RECs through May 2012. See Note 6– Derivative Financial Instruments
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
for additional information regarding ComEd’s financial swap contract with Generation and long-term renewable energy contracts.
On May 25, 2010, the ICC approved a Cash Working Capital (CWC) adjustment to be included in ComEd’s energy procurement tariff; however, the ICC did not specify the amount of the allowed recovery, which will ultimately be determined in an annual procurement reconciliation proceeding, based on information from ComEd’s most recent rate case. The approved CWC adjustment allows ComEd to recover the time value of money between when it is required to pay for energy and when funds are received from customers. ComEd began billing customers for CWC through its energy procurement rider on June 1, 2010 reflecting the costs included in ComEd’s original request to amend the tariff. Because of the uncertainty regarding the amount of CWC recovery, ComEd has been recording a reserve against a portion of these billings. The ICC order in the 2010 Rate Case clarifies the method for determining CWC, and as a result, ComEd reversed a $17 million reserve during the second quarter of 2011.
Pennsylvania Regulatory Matters
2010 Pennsylvania Electric and Natural Gas Distribution Rate Cases (Exelon and PECO). On December 16, 2010, the PAPUC approved the settlement of PECO’s electric and natural gas distribution rate cases for increases in annual service revenue of $225 million and $20 million, respectively. The electric settlement provides for recovery of PJM transmission service costs, on a full and current basis through a rider. In addition, the settlements included a stipulation regarding how potential tax benefits related to the application of the anticipated IRS guidance on repairs deduction methodology are to be handled from a rate-making perspective. The settlements require that any potential cash benefit from the application of the new methodology to prior tax years be refunded to customers over a seven-year period. Any prospective tax benefit claimed as a result of the new methodology is to be reflected in tax expense in the year in which it is claimed on the tax return and will be reflected in the determination of revenue requirements in the next electric and natural gas distribution base rate cases. See Note 8 — Income Taxes for additional information. The approved electric and natural gas distribution rates became effective on January 1, 2011.
Pennsylvania Procurement Proceedings (Exelon and PECO).PECO’s DSP Program, under which PECO is providing default electric service, has a 29-month term that began January 1, 2011 and ends May 31, 2013. Under the DSP Program, PECO is permitted to recover its electric procurement costs from retail default service customers without mark-up through the GSA. The GSA provides for the recovery of energy, capacity, ancillary costs and administrative costs and is subject to adjustments at least quarterly for any over or under collections. The filing and implementation costs of the DSP Program were recorded as a noncurrent regulatory asset and are being recovered through the GSA over its 29-month term. The hourly spot market price full requirements procurement tranches for large commercial and industrial default customers in the September 2010 procurement were not fully subscribed, therefore, PECO served the associated load through spot market purchases and separately procured AECs for the first five months of 2011. In May 2011, PECO entered into contracts with PAPUC-approved bidders for its competitive procurement of electric supply for default electric service commencing June 2011, which included hourly spot market price full requirements contracts to complete the unsubscribed tranches for its large commercial and industrial procurement classes and block energy contracts for the residential procurement class. PECO will conduct four additional competitive procurements over the remainder of the term of the DSP Program.
Electric Purchase of Receivables Program. PECO’s revised electric POR program requires PECO to purchase the customer accounts receivable of EGSs that participate in the electric customer choice program and have elected consolidated billing by PECO. The revised POR program became effective on January 1, 2011 and provides for full recovery of PECO’s system implementation costs for program administration through a
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
temporary discount on purchased receivables. The revised POR program was approved by the PAPUC on June 16, 2010 and allows PECO to terminate electric service to customers beginning January 1, 2011, based on unpaid charges for EGS service, and permits recovery of uncollectible accounts expense from customers through electric distribution rates. As of June 30, 2011, the balance of receivables purchased under the revised POR program were $45 million. Receivables purchased under the previous POR program were $3 million as of December 31, 2010. The increase in the POR receivable balance is a result of increased customer choice program participation following the expiration of the transition period. Prior to participation in the customer choice program, these receivables would have been recorded in customer accounts receivable. Receivables purchased under both programs are classified in other accounts receivable, net on Exelon and PECO’s Consolidated Balance Sheets.
Smart Meter and Smart Grid Investments (Exelon and PECO). In April 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan under which PECO will install more than 1.6 million smart meters and deploy advanced communication networks over a 10-year period. In 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA. Under the SGIG, PECO has been awarded $200 million, the maximum grant allowable under the program, for its SGIG project – Smart Future Greater Philadelphia. In total, through 2020, PECO plans to spend up to a total of $650 million on its smart grid and smart meter infrastructure. The $200 million SGIG is being used to reduce the impact of these investments on PECO ratepayers.
During the six months ending June 30, 2011, PECO received $30 million in reimbursements from the DOE. As of June 30, 2011, PECO’s outstanding receivable from the DOE for reimbursable costs was $26 million, which has been recorded in other accounts receivable, net on Exelon’s and PECO’s Consolidated Balance Sheets.
On April 15, 2011, the PAPUC issued the order approving the joint petition for partial settlement of the initial dynamic pricing and customer acceptance plan and ruled that the administrative costs be recovered from default service customers through the GSA. PECO plans to file for approval of a universal meter deployment plan for its remaining customers in 2012.
Energy Efficiency Programs (Exelon and PECO). On July 15, 2011, PECO filed a petition to make adjustments to its PAPUC-approved four-year EE&C Plan, which began in 2009. The plan includes a CFL program, weatherization programs, an energy efficiency appliance rebate and recycling program and rebates for non-profit, educational, governmental and business customers, customer incentives for energy management programs and incentives to help customers reduce energy demand during peak periods. The filing noted that PECO has exceeded the 1% energy use reduction target required by May 31, 2011; the proposed adjustments will allow PECO to meet its May 31, 2013 targets for energy use and energy demand reductions, while remaining within its approved plan budget.
Alternative Energy Portfolio Standards (Exelon and PECO). The AEPS Act mandated that, beginning in 2011, certain percentages of electric energy sold to Pennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement for electric energy that must come from Tier I alternative energy resources ranges from approximately 3.5% to 8.0% and the requirement for Tier II alternative energy resources ranges from 6.2% to 10.0%. The required compliance percentages incrementally increase each annual compliance period, which is from June 1 through May 31, until May 31, 2021. On February 10, 2011, the PAPUC approved PECO’s petition related to the procurement of supplemental AECs and Tier II AECs and the purchase and sale of excess AECs through independent third party auctions or brokers. On May 10, 2011, the PAPUC approved PECO’s procurement of 340,000 Tier II AECs that will be used to meet AEPS obligations in the 2011 and 2012 compliance years.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The AECs procured prior to the 2011 compliance year were banked and are anticipated to be used to meet AEPS obligations over two compliance periods ending May 2013, in accordance with the petition approved on February 10, 2011, by the PAPUC. Administrative costs and the costs of the banked AECs are being recovered with a return on the unamortized balance over a twelve month period that began January 1, 2011. All AEPS administrative costs and costs of AECs incurred after December 31, 2010 will be recovered on a full and current basis through a rider.
Natural Gas Choice Supplier Tariff (Exelon and PECO) On March 11, 2011, PECO filed tariff supplements to its Gas Choice Supplier Coordination Tariff and the Retail Gas Service Tariff to address the new licensing requirements for natural gas suppliers outlined in the PAPUC’s final rulemaking order that became effective January 1, 2011. The new licensing requirements broaden the types of collateral that PECO can obtain to mitigate its risk related to a natural gas choice supplier default and PECO’s ability to adjust collateral when material changes in supplier creditworthiness exist.
Federal Regulatory Matters
Annual Transmission Formula Rate Update (Exelon and ComEd).ComEdComEd’s transmission rates are established based on a FERC-approved formula.). ComEd’s most recent annual formula rate update filed in May 20102011 reflects actual 20092010 expenses and investments plus forecasted 20102011 capital additions. The update resulted in a revenue requirement of $430$438 million offset by a $14$16 million reduction related to the true-up of 20092010 actual costs for a net revenue requirement of $416$422 million. This compares to the May 20092010 updated net revenue requirement of $440$416 million. The decreaseincrease in the revenue requirement was primarily driven by ComEd’s 2009 cost savings measures.the Illinois income tax statutory rate change enacted in January 2011. The 20102011 net revenue requirement became effective June 1, 20102011 and is recovered over the period extending through May 31, 2011.2012. The regulatory liability associated with the true-up is being amortized as the associated revenuesamounts are refunded.
ComEd’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 9.27%9.10%, a decrease from the 9.43%9.27% return previously authorized. As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at 56%55%. This equity cap will be reduced to 55% in June 2011.
Pennsylvania Electric and Natural Gas Distribution Rate CasesMarket-Based Rates (Exelon, Generation, ComEd and PECO).On March 31, 2010,Generation, ComEd and PECO filed separate petitions before the PAPUCare public utilities for increases of $316 million and $44 million to its annual service revenue requirement for electric and natural gas delivery, respectively, to fund critical infrastructure improvement projects to meet customer demand and ensure the safe and reliable delivery of electricity and natural gas. The requested rate of return on common equity under the electric and natural gas delivery rate cases is 11.75%. The requested increase in delivery rates charged to customers for electric and natural gas as a resultpurposes of the Federal Power Act and are required to obtain FERC’s acceptance of rate cases is 6.94%schedules for wholesale electricity sales. Currently, Generation, ComEd and 5.28%, respectively.PECO have authority to execute wholesale electricity sales at market-based rates. In the most recent market power analysis for the PJM region, Generation informed FERC that its market share data in PJM would change beginning in 2011, when Generation’s contract for PECO’s full requirements for capacity and energy expired. The new electricFERC Staff asked for a letter describing the amount of capacity affected by the PECO contract expiration and gas delivery rates would take effect no later than January 1,alternative transactions, which Generation filed on March 21, 2011. The resultsimpact of that change, as well as that of any new sales contracts or other intervening changes in Generation’s market share, will be reflected in the rate cases are expectednext updated market share screen analysis due to be knownfiled at the end of 2013. In the meantime, under FERC’s rules and precedent, any market power concerns would be obviated by FERC-approved RTO market monitoring and mitigation program in PJM. On June 22, 2011, FERC issued an order confirming Generation’s continued authority to charge market based rates, stating that any market power concerns are adequately addressed by PJM’s monitoring and mitigation program.
PJM Minimum Offer Price Rule (Exelon and Generation). PJM’s capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the fourth quartercompetitive price signals for generation capacity. On February 1, 2011, in response to the enactment of 2010. PECO cannot predict how muchNew Jersey Senate Bill 2381, Generation joined a group of the requested increases the PAPUC may approve.
generating companies, PJM Power Providers Group (P3),
32
(Dollars in millions, except per share data, unless otherwise noted)
in filing a complaint asking FERC to revise PJM’s MOPR to mitigate this exercise of buyer market power. In response to P3’s complaint, PJM filed a tariff amendment on February 11, 2011, to improve the MOPR. PJM’s filing differs in some ways from P3’s proposal, but in general P3 supports PJM’s filing. P3 and PECO). In 2009,PJM requested that FERC act on the PAPUC entered an Order instituting an investigation into whether PECO’s nuclear decommissioning cost adjustment clause (NDCAC), which is a mechanism that allows PECOproposed tariff amendment prior to recover costs from customers for the decommissioningMay 2011 capacity auction. A number of seven former PECO nuclear units now owned by Generation, should continue after December 31, 2010. The Pennsylvania Offices of Trial Staff, Consumer Advocate, Small Business Advocatestate regulators and a group of industrial customers (collectively,consumer groups have opposed the parties) intervenedtariff changes, but these changes are in line with recent FERC orders regarding capacity markets in the proceeding. During the course of the investigation, PECONew York and the parties reached an agreement, as set forth in a Stipulation and Joint Memorandum filed on February 24, 2010 (Settlement) that PECO is entitled to recover decommissioning costs through the NDCAC beyond December 31, 2010. The Settlement also contained a provision in which it was agreed that PECO would not claim recovery under the NDCAC for any incremental physical decommissioning costs incurred with respect to any former PECO nuclear unit as a result of an extension of a unit’s NRC Operating License. On March 16, 2010, the ALJ issued a Recommended Decision, which concluded that PECO’s NDCAC should remain in effect beyond December 31, 2010, and recommended approval of the Settlement subject to a modification. Specifically, the ALJ stated that the provision regarding the recovery of incremental physical decommissioning costs is outside the scope of this investigation and is more appropriately considered in the NDCAC filings that are made every 5 years. Accordingly, the ALJ declined to approve this provision of the Settlement. On April 8, 2010, the parties filed exceptions to the ALJ’s proposed modification of the Settlement. On July 15, 2010, the PAPUC granted the parties’ exceptions and approved the Settlement in its entirety without the modification recommended by the ALJ. See Note 10 — Nuclear Decommissioning for additional information.
33
License Renewals (Exelon and increase Smart Grid investmentsGeneration) On August 18, 2009, PSEG submitted applications to approximately $100 million over the next threeNRC to extend the operating licenses of Salem Units 1 and 2 by 20 years. Exelon is a 42.59% owner of the Salem Units. On June 30, 2011, the NRC issued the renewed operating licenses for Salem Units 1 and 2 expiring in 2036 and 2040, respectively.
On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The $200 million SGIG funds will be reimbursed ratably based on projected spending of more than $400 million, which includes approximately $7 million relatedNRC is expected to demonstration projects by two sub-recipients. The SGIG is non-taxable based on recent IRS guidance. The DOE has a conditional ownership interest in federally-funded project property and equipment, which is subordinate to PECO’s existing mortgage. In total, over the next 10 years, PECO is planning to spend up to a total of $650 million on its smart grid22 to 30 months to review the applications before making a decision. The current operating licenses for Limerick Units 1 and smart meter infrastructure. The $200 million SGIG from the DOE will be used to significantly reduce the impact of those investments on PECO ratepayers.
Regulatory Assets and Liabilities (Exelon, ComEd and PECO)
Exelon, ComEd and PECO prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
34
(Dollars in millions, except per share data, unless otherwise noted)
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd and PECO as of June 30, 20102011 and December 31, 2009.2010. For additional information on the specific regulatory assets and liabilities, refer to Note 192 of the 20092010 Form 10-K.
June 30, 2010 | Exelon | ComEd | PECO | |||||||||
Regulatory assets | ||||||||||||
Competitive transition charge | $ | 438 | $ | — | $ | 438 | ||||||
Pension and other postretirement benefits | 2,540 | — | 16 | |||||||||
Deferred income taxes | 851 | 21 | 830 | |||||||||
Smart meter program expenses | 3 | — | 3 | |||||||||
Smart meter accelerated depreciation | 3 | — | 3 | |||||||||
Debt costs | 131 | 114 | 17 | |||||||||
Severance | 84 | 84 | — | |||||||||
Asset retirement obligations | 66 | 50 | 16 | |||||||||
MGP remediation costs | 136 | 97 | 39 | |||||||||
RTO start-up costs | 11 | 11 | — | |||||||||
Under-recovered uncollectible accounts | 49 | 49 | — | |||||||||
Financial swap with Generation — noncurrent | — | 627 | — | |||||||||
DSP Program electric procurement contracts - noncurrent | 2 | — | 4 | |||||||||
DSP Program costs | 6 | — | 6 | |||||||||
Other | 60 | 29 | 31 | |||||||||
Noncurrent regulatory assets | 4,380 | 1,082 | 1,403 | |||||||||
Financial swap with Generation — current | — | 383 | — | |||||||||
Under-recovered energy and transmission costs current asset | 14 | 14 | — | |||||||||
DSP Program electric procurement contracts — current | 2 | — | 5 | |||||||||
Total regulatory assets | $ | 4,396 | $ | 1,479 | $ | 1,408 | ||||||
Regulatory liabilities | ||||||||||||
Nuclear decommissioning (a) | $ | 2,069 | $ | 1,797 | $ | 272 | ||||||
Removal costs | 1,229 | 1,229 | — | |||||||||
Refund of PURTA taxes | 4 | — | 4 | |||||||||
Energy efficiency and demand response programs | 41 | 19 | 22 | |||||||||
Other | 1 | — | 1 | |||||||||
Noncurrent regulatory liabilities | 3,344 | 3,045 | 299 | |||||||||
Over-recovered energy and transmission costs current liability | 51 | 13 | 38 | |||||||||
Total regulatory liabilities | $ | 3,395 | $ | 3,058 | $ | 337 | ||||||
December 31, 2009 | Exelon | ComEd | PECO | |||||||||
Regulatory assets | ||||||||||||
Competitive transition charge | $ | 883 | $ | — | $ | 883 | ||||||
Pension and other postretirement benefits | 2,634 | — | 19 | |||||||||
Deferred income taxes | 842 | 20 | 822 | |||||||||
Debt costs | 144 | 125 | 19 | |||||||||
Severance | 95 | 95 | — | |||||||||
Asset retirement obligations | 65 | 49 | 16 | |||||||||
MGP remediation costs | 143 | 103 | 40 | |||||||||
RTO start-up costs | 12 | 12 | — | |||||||||
Financial swap with Generation—noncurrent | — | 669 | — | |||||||||
DSP Program electric procurement contracts | 2 | — | 4 | |||||||||
DSP Program costs | 5 | — | 5 | |||||||||
Other | 47 | 23 | 26 | |||||||||
Noncurrent regulatory assets | 4,872 | 1,096 | 1,834 | |||||||||
Financial swap with Generation—current | — | 302 | — | |||||||||
Under-recovered energy and transmission costs current asset | 56 | 56 | — | |||||||||
Total regulatory assets | $ | 4,928 | $ | 1,454 | $ | 1,834 | ||||||
Regulatory liabilities | ||||||||||||
Nuclear decommissioning (a) | $ | 2,229 | $ | 1,918 | $ | 311 | ||||||
Removal costs | 1,212 | 1,212 | — | |||||||||
Refund of PURTA taxes | 4 | — | 4 | |||||||||
Deferred taxes | 30 | — | — | |||||||||
Energy efficiency and demand response programs | 15 | 15 | — | |||||||||
Other | 2 | — | 2 | |||||||||
Noncurrent regulatory liabilities | 3,492 | 3,145 | 317 | |||||||||
Over-recovered energy and transmission costs current liability | 33 | 11 | 22 | |||||||||
Total regulatory liabilities | $ | 3,525 | $ | 3,156 | $ | 339 | ||||||
June 30, 2011 | Exelon | ComEd | PECO | |||||||||
Regulatory assets | ||||||||||||
Pension and other postretirement benefits | $ | 2,712 | $ | — | $ | 10 | ||||||
Deferred income taxes | 929 | 67 | (a) | 862 | ||||||||
Smart meter program expenses | 21 | — | 21 | |||||||||
Debt costs | 111 | 98 | 13 | |||||||||
Severance(b) | 76 | 76 | — | |||||||||
Asset retirement obligations | 88 | 62 | 26 | |||||||||
MGP remediation costs | 145 | 104 | 41 | |||||||||
RTO start-up costs | 9 | 9 | — | |||||||||
Financial swap with Generation — noncurrent | — | 345 | — | |||||||||
Renewable energy and associated RECs — noncurrent(c) | 30 | 30 | — | |||||||||
DSP Program costs | 6 | — | 6 | |||||||||
Other | 62 | 31 | 31 | |||||||||
Noncurrent regulatory assets | 4,189 | 822 | 1,010 | |||||||||
Financial swap with Generation — current | — | 412 | — | |||||||||
Under-recovered energy and transmission costs | 122 | 92 | 30 | (d) | ||||||||
DSP Program electric procurement contracts(e) | 2 | — | 4 | |||||||||
Renewable energy and associated RECs — current(c) | 1 | 1 | — | |||||||||
Current regulatory assets | 125 | 505 | 34 | |||||||||
Total regulatory assets | $ | 4,314 | $ | 1,327 | $ | 1,044 | ||||||
Regulatory liabilities | ||||||||||||
Nuclear decommissioning(f) | $ | 2,380 | $ | 1,979 | $ | 402 | ||||||
Removal costs | 1,227 | 1,227 | — | |||||||||
Refund of PURTA taxes | 2 | — | 2 | |||||||||
Energy efficiency and demand response programs | 87 | 34 | 53 | |||||||||
Over-recovered uncollectible accounts | 10 | 10 | — | |||||||||
Noncurrent regulatory liabilities | 3,706 | 3,250 | 457 | |||||||||
Over-recovered energy and transmission costs | 55 | 23 | 32 | (g) | ||||||||
Over-recovered universal service fund costs(h) | 3 | — | 3 | |||||||||
Over-recovered AEPS costs | 5 | — | 5 | |||||||||
Current regulatory liabilities | 63 | 23 | 40 | |||||||||
Total regulatory liabilities | $ | 3,769 | $ | 3,273 | $ | 497 | ||||||
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
December 31, 2010 | Exelon | ComEd | PECO | |||||||||
Regulatory assets | ||||||||||||
Pension and other postretirement benefits | $ | 2,763 | $ | — | $ | 13 | ||||||
Deferred income taxes | 852 | 23 | 829 | |||||||||
Smart meter program expenses | 17 | — | 17 | |||||||||
Debt costs | 123 | 108 | 15 | |||||||||
Severance | 74 | 74 | — | |||||||||
Asset retirement obligations | 86 | 61 | 25 | |||||||||
MGP remediation costs | 149 | 110 | 39 | |||||||||
RTO start-up costs | 10 | 10 | — | |||||||||
Under-recovered uncollectible accounts | 14 | 14 | — | |||||||||
Financial swap with Generation — noncurrent | — | 525 | — | |||||||||
DSP Program costs | 7 | — | 7 | |||||||||
Other | 45 | 22 | 23 | |||||||||
Noncurrent regulatory assets | 4,140 | 947 | 968 | |||||||||
Financial swap with Generation — current | — | 450 | — | |||||||||
Under-recovered energy and transmission costs | 6 | 6 | — | |||||||||
DSP Program electric procurement contracts(e) | 4 | — | 9 | |||||||||
Current regulatory assets | 10 | 456 | 9 | |||||||||
Total regulatory assets | $ | 4,150 | $ | 1,403 | $ | 977 | ||||||
Regulatory liabilities | ||||||||||||
Nuclear decommissioning(f) | $ | 2,267 | $ | 1,892 | $ | 375 | ||||||
Removal costs | 1,211 | 1,211 | — | |||||||||
Renewable energy and associated RECs — noncurrent(c) | 4 | 4 | — | |||||||||
Refund of PURTA taxes | 4 | — | 4 | |||||||||
Energy efficiency and demand response programs | 69 | 31 | 38 | |||||||||
Other | — | (1 | ) | 1 | ||||||||
Noncurrent regulatory liabilities | 3,555 | 3,137 | 418 | |||||||||
Over-recovered energy and transmission costs | 44 | 19 | 25 | (g) | ||||||||
Current regulatory liabilities | 44 | 19 | 25 | |||||||||
Total regulatory liabilities | $ | 3,599 | $ | 3,156 | $ | 443 | ||||||
(a) | Includes a regulatory asset at ComEd recorded pursuant to the 2010 Rate Case order for the recovery of costs related to the passage of the Health Care Reform Acts in 2010. Also includes a regulatory asset at ComEd recorded as a result of a change in the Illinois corporate tax rate during January 2011. See Note 8 — Income Taxes for additional information. |
(b) | Includes $13 million at ComEd recorded pursuant to the 2010 Rate Case order to recover costs related to the 2009 Exelon restructuring plan. |
(c) | These amounts represent the unrealized losses (regulatory asset) or gains (regulatory liability) on 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers at ComEd. See Note 6 — Derivative Financial Instruments for additional information. |
(d) | Includes $24 million related to under-recovered electric supply costs and $6 million related to under-recovered transmission costs. |
(e) | As of June 30, 2011 and December 31, 2010, PECO recorded a regulatory asset to offset the current mark-to-market liability recorded for derivative block contracts. See Note 6 — Derivative Financial Instruments for additional information. |
(f) | These amounts represent estimated future nuclear decommissioning costs that are less than the associated NDT fund assets. These regulatory liabilities have an equal and offsetting noncurrent receivable from affiliate at ComEd and PECO, and a noncurrent payable to affiliate recorded at Generation equal to the total regulatory liability at Exelon, ComEd and PECO. See Note |
(g) | Relates to the over-recovered natural gas costs under the PGC. |
(h) | The universal services fund cost is a recovery mechanism that allows for PECO to recover discounts issued to electric and gas customers enrolled in assistance programs. As of June 30, 2011, PECO was over-recovered for its electric and gas programs. |
35
(Dollars in millions, except per share data, unless otherwise noted)
Operating and Maintenance for Regulatory Required Programs (Exelon, ComEd and PECO)
The following tables set forth costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustmentRider clause for ComEd and PECO for the three and six months ended June 30, 20102011 and 2009.2010. An equal and offsetting amount has been reflected in operating revenues during the periods.
For the Three Months Ended June 30, 2010 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 33 | $ | 20 | (a) | $ | 13 | |||||
Purchased power administrative costs | 1 | 1 | — | |||||||||
Total operating and maintenance for regulatory required programs | $ | 34 | $ | 21 | $ | 13 | ||||||
For the Six Months Ended June 30, 2010 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 58 | $ | 38 | (a) | $ | 20 | |||||
Purchased power administrative costs | 2 | 2 | — | |||||||||
Consumer education program | 1 | — | 1 | (b) | ||||||||
Total operating and maintenance for regulatory required programs | $ | 61 | $ | 40 | $ | 21 | ||||||
For the Three Months Ended June 30, 2009 | Exelon | ComEd | ||||||
Energy efficiency and demand response programs | $ | 13 | $ | 13 | (a) | |||
Purchased power administrative costs | 1 | 1 | ||||||
Total operating and maintenance for regulatory required programs | $ | 14 | $ | 14 | ||||
For the Six Months Ended June 30, 2009 | Exelon | ComEd | ||||||
Energy efficiency and demand response programs | $ | 23 | $ | 23 | (a) | |||
Purchased power administrative costs | 2 | 2 | ||||||
Total operating and maintenance for regulatory required programs | $ | 25 | $ | 25 | ||||
For the Three Months Ended June 30, 2011 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 37 | $ | 22 | $ | 15 | ||||||
Smart meter program | 2 | — | 2 | |||||||||
Purchased power administrative costs | 2 | 1 | 1 | |||||||||
Total operating and maintenance for regulatory required programs | $ | 41 | $ | 23 | $ | 18 | ||||||
For the Six Months Ended June 30, 2011 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 70 | $ | 39 | $ | 31 | ||||||
Smart meter program | 4 | — | 4 | |||||||||
Purchased power administrative costs | 4 | 2 | 2 | |||||||||
Consumer education program | 1 | — | 1 | |||||||||
Total operating and maintenance for regulatory required programs | $ | 79 | $ | 41 | $ | 38 | ||||||
For the Three Months Ended June 30, 2010 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 33 | $ | 20 | $ | 13 | ||||||
Purchased power administrative costs | 1 | 1 | — | |||||||||
Total operating and maintenance for regulatory required programs | $ | 34 | $ | 21 | $ | 13 | ||||||
For the Six Months Ended June 30, 2010 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 58 | $ | 38 | $ | 20 | ||||||
Purchased power administrative costs | 2 | 2 | — | |||||||||
Consumer education program | 1 | — | 1 | |||||||||
Total operating and maintenance for regulatory required programs | $ | 61 | $ | 40 | $ | 21 | ||||||
36
On April 28, 2011, Exelon and Constellation Energy Group, Inc. (Constellation) announced that they signed an agreement and plan of merger to combine the two companies in a stock-for-stock transaction. Under the merger agreement, Constellation’s shareholders will receive 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock. Based on Exelon’s closing share price on April 27, 2011, Constellation shareholders would receive $7.9 billion in total equity value. The resulting company will retain the Exelon name and be headquartered in Chicago.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
a material overlap of generation owned by both companies. These stations, Brandon Shores and H.A. Wagner in Anne Arundel County, Md., and C.P. Crane in Baltimore County, Md., include base-load coal-fired generation units plus associated gas/oil units located at the same sites, and total 2,648 MW of generation capacity. In addition, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), the transaction cannot be completed until Exelon has made required notifications and given certain information and materials to the Federal Trade Commission (FTC) and/or the Antitrust Division of the United States Department of Justice (DOJ) and until specified waiting period requirements have expired. During the second quarter, Exelon and Constellation filed applications with FERC, the MDPSC, the New York State Public Service Commission and the Public Utility Commission of Texas seeking approval of the transaction. Exelon and Constellation also filed an application with the NRC for indirect transfer of Constellation licenses and filed notifications with the FTC and DOJ in compliance with the requirements of the HSR Act.
Exelon has been named in suits filed in the Circuit Court of Baltimore City, Maryland alleging that individual directors of Constellation breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin a Constellation shareholder vote on the proposed merger until all material information is disclosed and seek rescission of the proposed merger. In addition, they also seek compensatory damages, rescission damages, attorneys’ fees and costs. Exelon intends to vigorously defend these suits. Exelon does not believe these suits will impact the completion of the transaction and are not expected to have a material impact on Exelon’s results of operations.
Through June 30, 2011, Exelon has incurred approximately $24 million of expense associated with the transaction, primarily related to fees incurred as part of the acquisition. Exelon currently estimates the total costs directly related to closing the transaction will be $144 million, which include financial advisor, consultant, legal and SEC registration fees. In addition, Exelon estimates approximately $500 million of additional integration costs, primarily in 2012 and 2013. Such costs are expected to be partially offset by projected merger-related synergies in 2012 and fully offset in 2013 and beyond. As part of the application for approval of the merger by MDPSC, Exelon and Constellation have proposed a package of benefits to Baltimore Gas and Electric Company customers, the City of Baltimore and the state of Maryland, which results in a direct investment in the state of Maryland of more than $250 million. Under the merger agreement, in the event Exelon or Constellation terminates the merger agreement to accept a superior proposal, or under certain other circumstances, Exelon or Constellation, as applicable, would be required to pay a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon. The companies anticipate closing the transaction in early 2012.
Proposed Acquisition of Wolf Hollow (Exelon and Generation)
On May 12, 2011, Generation entered into an agreement to acquire Wolf Hollow, a combined-cycle natural gas-fired power plant in north Texas, for approximately $305 million. Under the terms of the agreement, Generation will acquire 720 MWs of energy within the ERCOT power market. The agreement is contingent upon antitrust clearance and Texas regulatory approval. The approval process is expected to be completed and the transaction is expected to close during the third quarter of 2011. In connection with the proposed acquisition, Generation’s existing long-term PPA with Wolf Hollow will be terminated upon completion of the transaction. As of June 30, 2011, Generation’s energy purchase commitments related to the Wolf Hollow PPA were approximately $340 million. Wolf Hollow will not be a “significant subsidiary,” as defined by SEC financial statement reporting requirements, for Exelon or Generation.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Acquisition of John Deere Renewables (Exelon and Generation)
On December 9, 2010, Generation completed the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind), a leading operator and developer of wind power. Under the terms of the agreement, Generation acquired 735 MWs of installed, operating wind capacity located in eight states. The acquisition builds on Exelon’s commitment to renewable energy as part of Exelon 2020, a business and environmental strategy to eliminate the equivalent of Exelon’s 2001 carbon footprint.
The fair value of assets acquired and liabilities assumed was determined based upon the use of significant estimates and assumptions that are judgmental in nature. Some of the more significant estimates and assumptions used include: projected future cash flows (including timing); discount rates reflecting the risk inherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and the duration of the liabilities assumed. Generation did not record any goodwill related to the acquisition of Exelon Wind.
The following table summarizes the fair value of consideration transferred to acquire Exelon Wind and the value of identified assets and liabilities assumed as of the acquisition date:
Fair Value of Consideration Transferred
Cash(a) | $ | 893 | ||
Contingent consideration | 32 | |||
Total fair value of consideration recorded | $ | 925 | ||
Recognized amounts of identifiable assets acquired and liabilities assumed | ||||
Property, plant and equipment | $ | 700 | ||
Intangible assets | 224 | |||
Working capital | 18 | |||
Asset retirement obligations | (13 | ) | ||
Noncontrolling interest | (3 | ) | ||
Other | (1) | |||
Total net identifiable assets | $ | 925 | ||
(a) | On September 30, 2010, Generation issued $900 million of senior notes, the proceeds of which were used to fund the acquisition. |
The contingent consideration arrangement requires that Generation pay up to $40 million related to three individual projects with a capacity of 230 MWs, which are currently in advanced stages of development, upon meeting certain contractual commitments related to the commencement of construction of each project. The fair value of the contingent consideration arrangement of $32 million was determined based upon a weighted average probability of meeting certain contractual commitments related to the commencement of construction of each project, which is considered an unobservable (Level 3) input pursuant to applicable accounting guidance. As of June 30, 2011, the amount recognized for the contingent consideration arrangement, the range of outcomes, and the assumptions used to develop the estimate had not changed since December 31, 2010. Generation anticipates paying a portion of the contingent consideration within the next 12 months and, accordingly, $24 million of contingent consideration is included within other current liabilities within Exelon and Generation’s Consolidated Balance Sheets. The remaining amount was recorded in other deferred credits and other liabilities within Exelon and Generation’s Consolidated Balance Sheets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The fair value of the assets acquired included customer receivables of $18 million. As of June 30, 2011, there are no outstanding customer receivables that were acquired in the Exelon Wind transaction.
The $3 million noncontrolling interest represents the noncontrolling members’ proportionate share in the fair value of the assets acquired and liabilities assumed in the transaction.
The unaudited pro forma results for Exelon and Generation as if the Exelon Wind acquisition occurred on January 1, 2009 were not materially different from Exelon and Generation’s financial results for the three and six months ended June 30, 2010.
Accounting guidance requires that the acquirer must recognize separately identifiable intangible assets in the application of purchase accounting. Most of the output of the acquired wind turbines has been sold under PPA contracts. The excess of the contract price of the PPAs over market prices was recognized as intangible assets. Generation determined that the estimated acquisition-date fair value of the intangible assets was approximately $224 million, which was recorded in other deferred debits and other assets within Exelon and Generation’s Consolidated Balance Sheets. Included in this amount is $48 million related to the PPAs for the projects that are in the advanced stage of development. While Generation expects to perform under the PPAs once the construction of these projects is complete, there is a risk of impairment if the projects do not reach commercial operation. The valuation of the acquired intangible assets was estimated by applying the income approach, which is based upon discounted projected future cash flows associated with the PPA contracts. That measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include forecasted power prices and discount rate. The intangible assets are amortized on a straight-line basis over the period in which the associated contract revenues are recognized. Generation determined that the unit of production amortization method would best reflect when the intangible assets’ economic benefits would be consumed; however, the straight-line method approximates the equivalent of the unit of production method on an annual basis. The amortization expense is reflected as a decrease in operating revenue within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. Amortization expense related to Exelon and Generation’s acquired intangible assets for the three and six months ended June 30, 2011 was $3 million and $6 million, respectively.
Exelon’s and Generation’s other acquired intangible assets, included in deferred debits and other assets in the Consolidated Balance Sheets, consisted of the following as of June 30, 2011:
Estimated amortization expense | ||||||||||||||||||||||||||||||||
Gross | Accumulated Amortization | Net | Second Half of 2011 | 2012 | 2013 | 2014 | 2015 | |||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||||||||
Exelon Wind acquisition | $ | 224 | $ | (7 | ) | $ | 217 | $ | 6 | $ | 13 | $ | 14 | $ | 14 | $ | 14 | |||||||||||||||
Total intangible assets | $ | 224 | $ | (7 | ) | $ | 217 | $ | 6 | $ | 13 | $ | 14 | $ | 14 | $ | 14 | |||||||||||||||
Non-Derivative Financial Assets and Liabilities. As of June 30, 20102011 and December 31, 2009,2010, the Registrants’ carrying amounts of cash and certain cash equivalents, accounts receivable, accounts payable, short-termshort term notes payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Fair Value of Financial Liabilities Recorded at the Carrying Amount
Exelon
The carrying amounts and fair values of Exelon’s long-term debt, spent nuclear fuelSNF obligation and preferred securities of subsidiary as of June 30, 20102011 and December 31, 20092010 were as follows:
June 30, 2010 | December 31, 2009 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 11,026 | $ | 12,077 | $ | 11,634 | $ | 12,223 | ||||||||
Long-term debt of variable interest entity due within one year (a) | 404 | 408 | — | — | ||||||||||||
Long-term debt to PETT due within one year (a) | — | — | 415 | 426 | ||||||||||||
Long-term debt to financing trusts | 390 | 332 | 390 | 325 | ||||||||||||
Spent nuclear fuel obligation | 1,018 | 864 | 1,017 | 832 | ||||||||||||
Preferred securities of subsidiary | 87 | 70 | 87 | 63 |
June 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 12,812 | $ | 13,746 | $ | 12,213 | $ | 12,960 | ||||||||
Long-term debt to financing trusts | 390 | 347 | 390 | 350 | ||||||||||||
SNF obligation | 1,019 | 897 | 1,018 | 876 | ||||||||||||
Preferred securities of subsidiary | 87 | 72 | 87 | 68 |
The fair value of long-term debt is determined using a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. The fair value of preferred securities of subsidiaries is determined using observable market prices as these securities are actively traded. The carrying amount of Exelon’s and Generation’s SNF obligation resulted from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. Exelon’s and Generation’s obligation to the DOE accrues at the 13-week Treasury rate and fair value was determined by comparing the carrying amount of the obligation at the 13-week Treasury rate to the present value of the obligation discounted using the prevailing Treasury rate for a long-term obligation with an estimated maturity of 2020 (after being adjusted for Generation’s credit risk).
Generation
The carrying amounts and fair values of Generation’s long-term debt and spent nuclear fuel obligations as of June 30, 20102011 and December 31, 20092010 were as follows:
June 30, 2010 | December 31, 2009 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,779 | $ | 3,021 | $ | 2,993 | $ | 3,132 | ||||||||
Spent nuclear fuel obligation | 1,018 | 864 | 1,017 | 832 |
June 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 3,678 | $ | 3,857 | $ | 3,679 | $ | 3,792 | ||||||||
SNF obligation | 1,019 | 897 | 1,018 | 876 |
ComEd
The carrying amounts and fair values of ComEd’s long-term debt as of June 30, 20102011 and December 31, 20092010 were as follows:
June 30, 2010 | December 31, 2009 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 4,712 | $ | 5,260 | $ | 4,711 | $ | 5,062 | ||||||||
Long-term debt to financing trust | 206 | 173 | 206 | 167 |
June 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 5,601 | $ | 6,131 | $ | 5,001 | $ | 5,411 | ||||||||
Long-term debt to financing trust | 206 | 176 | 206 | 176 |
37
(Dollars in millions, except per share data, unless otherwise noted)
PECO
The carrying amounts and fair values of PECO’s long-term debt and preferred securities as of June 30, 20102011 and December 31, 20092010 were as follows:
June 30, 2010 | December 31, 2009 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,221 | $ | 2,461 | $ | 2,221 | $ | 2,346 | ||||||||
Long-term debt of variable interest entity due within one year (a) | 404 | 408 | — | — | ||||||||||||
Long-term debt to PETT due within one year (a) | — | — | 415 | 426 | ||||||||||||
Long-term debt to financing trusts | 184 | 159 | 184 | 158 | ||||||||||||
Preferred securities | 87 | 70 | 87 | 63 |
June 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,222 | $ | 2,411 | $ | 2,222 | $ | 2,402 | ||||||||
Long-term debt to financing trusts | 184 | 172 | 184 | 173 | ||||||||||||
Preferred securities | 87 | 72 | 87 | 68 |
Recurring Fair Value Measurements
Exelon records the fair value measurements,of assets and liabilities in accordance with the FASBhierarchy established aby the authoritative guidance for fair value measurements. The hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to access as of the reporting date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded equity securities, exchange-based derivatives, mutual funds and money market funds.
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, non-exchange-based derivatives, commingled investment funds priced at NAV per fund share and fair value hedges.
Level 3 — unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded non-exchange-based derivatives.
There were no significant transfers between Level 1 and Level 2 during the six months ended June 30, 2011.
38
(Dollars in millions, except per share data, unless otherwise noted)
Exelon
The following tables present assets and liabilities measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 20102011 and December 31, 2009:
As of June 30, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 1,455 | $ | — | $ | — | $ | 1,455 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 53 | 73 | — | 126 | ||||||||||||
Equity securities(b) | 1,414 | — | — | 1,414 | ||||||||||||
Commingled funds(c) | — | 1,920 | — | 1,920 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 702 | 106 | — | 808 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 440 | — | 440 | ||||||||||||
Corporate debt securities | — | 719 | — | 719 | ||||||||||||
Federal agency mortgage-backed securities | — | 761 | — | 761 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 125 | — | 125 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 8 | — | 8 | ||||||||||||
Other debt obligations | — | 74 | 1 | 75 | ||||||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 2,169 | 4,226 | 1 | 6,396 | ||||||||||||
Rabbi trust investments | ||||||||||||||||
Cash equivalents | 24 | — | — | 24 | ||||||||||||
Mutual funds(e) | 13 | — | — | 13 | ||||||||||||
Rabbi trust investments subtotal | 37 | — | — | 37 | ||||||||||||
Mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 973 | 4 | 977 | ||||||||||||
Other derivatives | 3 | 1,852 | 72 | 1,927 | ||||||||||||
Proprietary trading | — | 287 | 47 | 334 | ||||||||||||
Effect of netting and allocation of collateral received/paid(f) | (6 | ) | (2,154 | ) | (33 | ) | (2,193 | ) | ||||||||
Mark-to-market assets(g) | (3 | ) | 958 | 90 | 1,045 | |||||||||||
Total assets | 3,658 | 5,184 | 91 | 8,933 | ||||||||||||
Liabilities | ||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges | — | (79 | ) | (3 | ) | (82 | ) | |||||||||
Other derivatives | (3 | ) | (948 | ) | (29 | ) | (980 | ) | ||||||||
Proprietary trading | — | (282 | ) | (13 | ) | (295 | ) | |||||||||
Effect of netting and allocation of collateral received/paid(f) | 3 | 1,270 | 22 | 1,295 | ||||||||||||
Mark-to-market liabilities(g) | — | (39 | ) | (23 | ) | (62 | ) | |||||||||
Deferred compensation | — | (70 | ) | — | (70 | ) | ||||||||||
Total liabilities | — | (109 | ) | (23 | ) | (132 | ) | |||||||||
Total net assets | $ | 3,658 | $ | 5,075 | $ | 68 | $ | 8,801 | ||||||||
As of June 30, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 450 | $ | — | $ | — | $ | 450 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 3 | 23 | — | 26 | ||||||||||||
Equity securities(b) | 1,425 | — | — | 1,425 | ||||||||||||
Commingled funds(c) | — | 2,280 | — | 2,280 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 518 | 110 | — | 628 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 563 | — | 563 | ||||||||||||
Corporate debt securities | — | 718 | — | 718 | ||||||||||||
Federal agency mortgage-backed securities | — | 763 | — | 763 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 128 | — | 128 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 6 | — | 6 | ||||||||||||
Other debt obligations | — | 78 | — | 78 | ||||||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 1,946 | 4,669 | — | 6,615 | ||||||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||
Equity securities(b) | 68 | — | — | 68 | ||||||||||||
Commingled funds(c) | — | 108 | — | 108 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 66 | 20 | — | 86 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 62 | — | 62 | ||||||||||||
Corporate debt securities | — | 316 | — | 316 | ||||||||||||
Federal agency mortgage-backed securities | — | 101 | — | 101 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 13 | — | 13 | ||||||||||||
Private equity | — | — | 34 | 34 | ||||||||||||
Other debt obligations | — | 8 | — | 8 | ||||||||||||
Pledged assets for Zion Station decommissioning subtotal(e) | 134 | 628 | 34 | 796 | ||||||||||||
Rabbi trust investments | ||||||||||||||||
Mutual funds(f) | 36 | — | — | 36 | ||||||||||||
Rabbi trust investments subtotal | 36 | — | — | 36 | ||||||||||||
Mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 481 | 2 | 483 | ||||||||||||
Other derivatives | — | 1,225 | 29 | 1,254 | ||||||||||||
Proprietary trading | — | 173 | 60 | 233 | ||||||||||||
Effect of netting and allocation of collateral(g) | (1 | ) | (1,167 | ) | (40 | ) | (1,208 | ) | ||||||||
Mark-to-market assets(h) | (1 | ) | 712 | 51 | 762 | |||||||||||
Total assets | 2,565 | 6,009 | 85 | 8,659 | ||||||||||||
Liabilities | ||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges | — | (82 | ) | (14 | ) | (96 | ) | |||||||||
Other derivatives | (1 | ) | (545 | ) | (58 | ) | (604 | ) | ||||||||
Proprietary trading | — | (171 | ) | (28 | ) | (199 | ) | |||||||||
Effect of netting and allocation of collateral(g) | 1 | 749 | 33 | 783 | ||||||||||||
Mark-to-market liabilities(h) | — | (49 | ) | (67 | ) | (116 | ) | |||||||||
Deferred compensation | — | (72 | ) | — | (72 | ) | ||||||||||
Total liabilities | — | (121 | ) | (67 | ) | (188 | ) | |||||||||
Total net assets | $ | 2,565 | $ | 5,888 | $ | 18 | $ | 8,471 | ||||||||
39
(Dollars in millions, except per share data, unless otherwise noted)
As of December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 1,845 | $ | — | $ | — | $ | 1,845 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 2 | 120 | — | 122 | ||||||||||||
Equity securities(b) | 1,528 | — | — | 1,528 | ||||||||||||
Commingled funds(c) | — | 2,086 | — | 2,086 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 511 | 119 | — | 630 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 454 | — | 454 | ||||||||||||
Corporate debt securities | — | 710 | — | 710 | ||||||||||||
Federal agency mortgage-backed securities | — | 887 | — | 887 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 91 | — | 91 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 9 | — | 9 | ||||||||||||
Other debt obligations | — | 76 | — | 76 | ||||||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 2,041 | 4,552 | — | 6,593 | ||||||||||||
Rabbi trust investments | ||||||||||||||||
Cash equivalents | 28 | — | — | 28 | ||||||||||||
Mutual funds(e) | 13 | — | — | 13 | ||||||||||||
Rabbi trust investments subtotal | 41 | — | — | 41 | ||||||||||||
Mark-to-market derivative net (liabilities) assets(f)(g) | (4 | ) | 852 | (44 | ) | 804 | ||||||||||
Total assets (liabilities) | 3,923 | 5,404 | (44 | ) | 9,283 | |||||||||||
Liabilities | ||||||||||||||||
Deferred compensation | — | (82 | ) | — | (82 | ) | ||||||||||
Servicing liability | — | — | (2 | ) | (2 | ) | ||||||||||
Total liabilities | — | (82 | ) | (2 | ) | (84 | ) | |||||||||
Total net assets | $ | 3,923 | $ | 5,322 | $ | (46 | ) | $ | 9,199 | |||||||
As of December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 1,473 | $ | — | $ | — | $ | 1,473 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 1 | — | — | 1 | ||||||||||||
Equity securities(b) | 1,513 | — | — | 1,513 | ||||||||||||
Commingled funds(c) | — | 2,212 | — | 2,212 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 504 | 96 | — | 600 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 451 | — | 451 | ||||||||||||
Corporate debt securities | — | 619 | — | 619 | ||||||||||||
Federal agency mortgage-backed securities | — | 804 | — | 804 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 114 | — | 114 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 14 | — | 14 | ||||||||||||
Other debt obligations | — | 48 | — | 48 | ||||||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 2,018 | 4,358 | — | 6,376 | ||||||||||||
Pledged assets for Zion decommissioning | ||||||||||||||||
Equity securities(b) | 84 | — | — | 84 | ||||||||||||
Commingled funds(c) | — | 132 | — | 132 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 166 | 12 | — | 178 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 45 | — | 45 | ||||||||||||
Corporate debt securities | — | 263 | — | 263 | ||||||||||||
Federal agency mortgage-backed securities | — | 102 | — | 102 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 14 | — | 14 | ||||||||||||
Other debt obligations | — | 2 | — | 2 | ||||||||||||
Pledged assets for Zion Station decommissioning subtotal(e) | 250 | 570 | — | 820 | ||||||||||||
Rabbi trust investments | ||||||||||||||||
Mutual funds(f) | 36 | — | — | 36 | ||||||||||||
Rabbi trust investments subtotal | 36 | — | — | 36 | ||||||||||||
Mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 724 | 12 | 736 | ||||||||||||
Other derivatives | 2 | 1,709 | 57 | 1,768 | ||||||||||||
Proprietary trading | — | 235 | 46 | 281 | ||||||||||||
Effect of netting and allocation of collateral(g) | (3 | ) | (1,848 | ) | (38 | ) | (1,889 | ) | ||||||||
Mark-to-market assets(h) | (1 | ) | 820 | 77 | 896 | |||||||||||
Total assets | 3,776 | 5,748 | 77 | 9,601 | ||||||||||||
Liabilities | ||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges | — | (45 | ) | — | �� | (45 | ) | |||||||||
Other derivatives | (2 | ) | (667 | ) | (29 | ) | (698 | ) | ||||||||
Proprietary trading | — | (233 | ) | (21 | ) | (254 | ) | |||||||||
Effect of netting and allocation of collateral(g) | 1 | 914 | 23 | 938 | ||||||||||||
Mark-to-market liabilities(h) | (1 | ) | (31 | ) | (27 | ) | (59 | ) | ||||||||
Deferred compensation | — | (76 | ) | — | (76 | ) | ||||||||||
Total liabilities | (1 | ) | (107 | ) | (27 | ) | (135 | ) | ||||||||
Total net assets | $ | 3,775 | $ | 5,641 | $ | 50 | $ | 9,466 | ||||||||
(a) | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |
(b) | Generation’s NDT funds and Zion Station decommissioning pledged assets hold equity portfolios whose performance is benchmarked against | |
(c) | Generation’s NDT funds and Zion Station decommissioning pledged assets own commingled funds that invest in | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(d) | Excludes net assets of | |
(e) | Excludes |
(f) | Excludes $26 million and $25 million of the cash surrender value of life insurance investments at June 30, |
Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled |
The Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of |
40
Nuclear | ||||||||||||
Decommissioning | ||||||||||||
Trust Fund | Mark-to-Market | |||||||||||
Three Months Ended June 30, 2010 (a) | Investments | Derivatives | Total | |||||||||
Balance as of March 31, 2010 | $ | — | $ | 33 | $ | 33 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in other comprehensive income | — | (11 | )(c) | (11 | ) | |||||||
Included in regulatory assets | — | 1 | 1 | |||||||||
Change in collateral | — | 9 | 9 | |||||||||
Purchases, sales, issuances, and settlements | ||||||||||||
Purchases | 1 | 11 | 12 | |||||||||
Transfers out of Level 3 — Liability | — | 24 | 24 | |||||||||
Balance as of June 30, 2010 | $ | 1 | $ | 67 | $ | 68 | ||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2010 | $ | — | $ | 1 | $ | 1 |
Nuclear | ||||||||||||||||
Decommissioning | ||||||||||||||||
Servicing | Trust Fund | Mark-to-Market | ||||||||||||||
Six Months Ended June 30, 2010 (a) | Liability | Investments | Derivatives | Total | ||||||||||||
Balance as of December 31, 2009 | $ | (2 | ) | $ | — | $ | (44 | ) | $ | (46 | ) | |||||
Total realized / unrealized gains (losses) | ||||||||||||||||
Included in income | 2 | (d) | — | 80 | (b) | 82 | ||||||||||
Included in other comprehensive income | — | — | 7 | (c) | 7 | |||||||||||
Included in regulatory assets | — | — | (2 | ) | (2 | ) | ||||||||||
Change in collateral | — | — | (8 | ) | (8 | ) | ||||||||||
Purchases, sales, issuances, and settlements | ||||||||||||||||
Purchases | — | 1 | 11 | 12 | ||||||||||||
Transfers out of Level 3 — Liability | — | — | 23 | 23 | ||||||||||||
Balance as of June 30, 2010 | $ | — | $ | 1 | $ | 67 | $ | 68 | ||||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2010 | $ | — | $ | — | $ | 78 | $ | 78 |
Three Months Ended June 30, 2011 | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Total | |||||||||
Balance as of March 31, 2011 | $ | 31 | $ | 51 | $ | 82 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in income | — | 21 | (a) | 21 | ||||||||
Included in other comprehensive income | — | (3 | )(b) | (3 | ) | |||||||
Included in regulatory assets | — | (85 | ) | (85 | ) | |||||||
Included in payable for Zion Station decommissioning | 3 | — | 3 | |||||||||
Change in collateral | — | 2 | 2 | |||||||||
Purchases, sales, issuances, and settlements | ||||||||||||
Purchases | 12 | 5 | 17 | |||||||||
Sales | (12 | ) | — | (12 | ) | |||||||
Transfers out of Level 3 — Asset | — | (7 | ) | (7 | ) | |||||||
Balance as of June 30, 2011 | $ | 34 | $ | (16 | ) | $ | 18 | |||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended June 30, 2011 | $ | — | $ | 30 | $ | 30 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2011 | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Total | |||||||||
Balance as of December 31, 2010 | $ | — | $ | 50 | $ | 50 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in income | — | 8 | (a) | 8 | ||||||||
Included in other comprehensive income | — | (12 | )(b) | (12 | ) | |||||||
Included in regulatory assets | — | (33 | ) | (33 | ) | |||||||
Included in payable for Zion Station decommissioning | 3 | — | 3 | |||||||||
Change in collateral | — | 7 | 7 | |||||||||
Purchases, sales, issuances, and settlements | ||||||||||||
Purchases | 43 | 5 | 48 | |||||||||
Sales | (12 | ) | — | (12 | ) | |||||||
Transfers out of Level 3 — Asset | — | (41 | ) | (41 | ) | |||||||
Balance as of June 30, 2011 | $ | 34 | $ | (16 | ) | $ | 18 | |||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the six months ended June 30, 2011 | $ | — | $ | 23 | $ | 23 |
(a) | Includes the reclassification of $9 million and $15 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2011, respectively. |
(b) | Excludes $65 million of decreases and $2 million of increases in fair value and $108 million and $220 million of realized losses due to settlements associated with Generation’s financial swap contract with ComEd and $2 million and $3 million of changes in the fair value of Generation’s block contracts with PECO for the three months and six months ended June 30, 2011, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements. |
Three Months Ended June 30, 2010 | Nuclear Decommissioning Trust Fund Investments | Mark-to-Market Derivatives | Total | |||||||||
Balance as of March 31, 2010 | $ | — | $ | 33 | $ | 33 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in other comprehensive income | — | (11 | )(b) | (11 | ) | |||||||
Included in regulatory assets | — | 1 | 1 | |||||||||
Change in collateral | — | 9 | 9 | |||||||||
Purchases, sales, issuances and settlements | ||||||||||||
Purchases | 1 | 11 | 12 | |||||||||
Transfers out of Level 3 — Liability | — | 24 | 24 | |||||||||
Balance as of June 30, 2010 | $ | 1 | $ | 67 | $ | 68 | ||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended June 30, 2010 | $ | — | $ | 1 | $ | 1 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2010 | Servicing Liability | Nuclear Decommissioning Trust Fund Investments | Mark-to-Market Derivatives | Total | ||||||||||||
Balance as of December 31, 2009 | $ | (2 | ) | $ | — | $ | (44 | ) | $ | (46 | ) | |||||
Total realized / unrealized gains (losses) | ||||||||||||||||
Included in income | 2 | (c) | — | 80 | (a) | 82 | ||||||||||
Included in other comprehensive income | — | — | 7 | (b) | 7 | |||||||||||
Included in regulatory assets | — | — | (2 | ) | (2 | ) | ||||||||||
Change in collateral | — | — | (8 | ) | (8 | ) | ||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||
Purchases | — | 1 | 11 | 12 | ||||||||||||
Transfers out of Level 3 — Liability | — | — | 23 | 23 | ||||||||||||
Balance as of June 30, 2010 | $ | — | $ | 1 | $ | 67 | $ | 68 | ||||||||
The amount of total gains included in income | ||||||||||||||||
attributed to the change in unrealized gains (losses) related to assets and liabilities held for the six months ended June 30, 2010 | $ | — | $ | — | $ | 78 | $ | 78 |
(a) | Includes the reclassification of $2 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the six months ended June 30, 2010. The reclassification due to settlement of derivative contracts for the three months June 30, 2010 was insignificant. |
(b) | Excludes $121 million of decreases in fair value and $199 million of increases in fair value and realized losses due to settlements of $104 million and $160 million associated with Generation’s financial swap contract with ComEd and $1 million of decreases in fair value and $3 million of increases in fair value of Generation’s block contracts with PECO for the three and six months ended June 30, 2010, respectively. All amounts eliminate upon consolidation in Exelon’s Consolidated Financial Statements. |
(c) | The servicing liability related to PECO’s accounts receivable agreement was released in accordance with new guidance on accounting for transfers of financial assets that was adopted on January 1, 2010. See Note 7 — Debt and Credit Agreements for additional information. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables present total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2011 and 2010:
Operating Revenue | Purchased Power | Fuel | Other, net | |||||||||||||
Total gains included in income for the three months ended June 30, 2011 | $ | 10 | $ | 10 | $ | 1 | $ | — | ||||||||
Total gains (losses) included in income for the six months ended | $ | 7 | $ | 3 | $ | (2 | ) | $ | — | |||||||
Change in the unrealized gains relating to assets and liabilities held for the three months ended June 30, 2011 | $ | 17 | $ | 11 | $ | 2 | $ | — | ||||||||
Change in the unrealized gains relating to assets and liabilities held for the six months ended June 30, 2011 | $ | 21 | $ | 2 | $ | — | $ | — |
Operating Revenue | Purchased Power | Fuel | Other, net | |||||||||||||
Total gains (losses) included in income for the three months ended June 30, 2010 | $ | 15 | $ | (20 | ) | $ | 5 | $ | — | |||||||
Total gains included in income for the six months ended June 30, 2010 | $ | 13 | $ | 36 | $ | 31 | $ | 2 | ||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended June 30, 2010 | $ | 20 | $ | (21 | ) | $ | 2 | $ | — | |||||||
Change in the unrealized gains relating to assets and liabilities held for the six months ended June 30, 2010 | $ | 23 | $ | 33 | $ | 22 | $ | — |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation
The following tables present assets and liabilities measured and recorded at fair value on Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2011 and December 31, 2010:
As of June 30, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 74 | $ | — | $ | — | $ | 74 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 3 | 23 | — | 26 | ||||||||||||
Equity securities(b) | 1,425 | — | — | 1,425 | ||||||||||||
Commingled funds(c) | — | 2,280 | — | 2,280 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 518 | 110 | — | 628 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 563 | — | 563 | ||||||||||||
Corporate debt securities | — | 718 | — | 718 | ||||||||||||
Federal agency mortgage-backed securities | — | 763 | — | 763 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 128 | — | 128 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 6 | — | 6 | ||||||||||||
Other debt obligations | — | 78 | — | 78 | ||||||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 1,946 | 4,669 | — | 6,615 | ||||||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||
Equity securities(b) | 68 | — | — | 68 | ||||||||||||
Commingled funds(c) | — | 108 | — | 108 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 66 | 20 | — | 86 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 62 | — | 62 | ||||||||||||
Corporate debt securities | — | 316 | — | 316 | ||||||||||||
Federal agency mortgage-backed securities | — | 101 | — | 101 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 13 | — | 13 | ||||||||||||
Private equity | — | — | 34 | 34 | ||||||||||||
Other debt obligations | — | 8 | — | 8 | ||||||||||||
Pledged assets for Zion Station decommissioning subtotal(e) | 134 | 628 | 34 | 796 | ||||||||||||
Rabbi trust investments(f)(g) | 4 | — | — | 4 | ||||||||||||
Mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 481 | 761 | 1,242 | ||||||||||||
Other derivatives | — | 1,211 | 29 | 1,240 | ||||||||||||
Proprietary trading | — | 173 | 60 | 233 | ||||||||||||
Effect of netting and allocation of collateral(h) | (1 | ) | (1,167 | ) | (40 | ) | (1,208 | ) | ||||||||
Mark-to-market assets(i) | (1 | ) | 698 | 810 | 1,507 | |||||||||||
Total assets | 2,157 | 5,995 | 844 | 8,996 | ||||||||||||
Liabilities | ||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges | — | (82 | ) | (14 | ) | (96 | ) | |||||||||
Other derivatives | (1 | ) | (545 | ) | (25 | ) | (571 | ) | ||||||||
Proprietary trading | — | (171 | ) | (28 | ) | (199 | ) | |||||||||
Effect of netting and allocation of collateral(h) | 1 | 749 | 33 | 783 | ||||||||||||
Mark-to-market liabilities | — | (49 | ) | (34 | ) | (83 | ) | |||||||||
Deferred compensation | — | (17 | ) | — | (17 | ) | ||||||||||
Total liabilities | — | (66 | ) | (34 | ) | (100 | ) | |||||||||
Total net assets | $ | 2,157 | $ | 5,929 | $ | 810 | $ | 8,896 | ||||||||
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
As of December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 419 | $ | — | $ | — | $ | 419 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 1 | — | — | 1 | ||||||||||||
Equity securities(b) | 1,513 | — | — | 1,513 | ||||||||||||
Commingled funds(c) | — | 2,212 | — | 2,212 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 504 | 96 | — | 600 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 451 | — | 451 | ||||||||||||
Corporate debt securities | — | 619 | — | 619 | ||||||||||||
Federal agency mortgage-backed securities | — | 804 | — | 804 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 114 | — | 114 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 14 | — | 14 | ||||||||||||
Other debt obligations | — | 48 | — | 48 | ||||||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 2,018 | 4,358 | — | 6,376 | ||||||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||
Equity securities(b) | 84 | — | — | 84 | ||||||||||||
Commingled funds(c) | — | 132 | — | 132 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 166 | 12 | — | 178 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 45 | — | 45 | ||||||||||||
Corporate debt securities | — | 263 | — | 263 | ||||||||||||
Federal agency mortgage-backed securities | — | 102 | — | 102 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 14 | — | 14 | ||||||||||||
Other debt obligations | — | 2 | — | 2 | ||||||||||||
Pledged assets for Zion Station decommissioning subtotal(e) | 250 | 570 | — | 820 | ||||||||||||
Rabbi trust investments(f)(g) | 4 | — | — | 4 | ||||||||||||
Mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 724 | 992 | 1,716 | ||||||||||||
Other derivatives | 2 | 1,695 | 53 | 1,750 | ||||||||||||
Proprietary trading | — | 235 | 46 | 281 | ||||||||||||
Effect of netting and allocation of collateral(h) | (3 | ) | (1,848 | ) | (38 | ) | (1,889 | ) | ||||||||
Mark-to-market assets(i) | (1 | ) | 806 | 1,053 | 1,858 | |||||||||||
Total assets | 2,690 | 5,734 | 1,053 | 9,477 | ||||||||||||
Liabilities | ||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges | — | (45 | ) | — | (45 | ) | ||||||||||
Other derivatives | (2 | ) | (667 | ) | (25 | ) | (694 | ) | ||||||||
Proprietary trading | — | (233 | ) | (21 | ) | (254 | ) | |||||||||
Effect of netting and allocation of collateral(h) | 1 | 914 | 23 | 938 | ||||||||||||
Mark-to-market liabilities | (1 | ) | (31 | ) | (23 | ) | (55 | ) | ||||||||
Deferred compensation | — | (20 | ) | — | (20 | ) | ||||||||||
Total liabilities | (1 | ) | (51 | ) | (23 | ) | (75 | ) | ||||||||
Total net assets | $ | 2,689 | $ | 5,683 | $ | 1,030 | $ | 9,402 | ||||||||
(a) | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. |
(b) | Generation’s NDT funds and Zion Station decommissioning pledged assets hold equity portfolios whose performance is benchmarked against established indices. |
(c) | Generation’s NDT funds and Zion Station decommissioning pledged assets own commingled funds that invest in equity securities. Generation’s NDT funds also own commingled funds that invest in fixed income securities. The commingled funds seek to out-perform certain established indices. |
(d) | Excludes net assets of $84 million and $32 million at June 30, 2011 and December 31, |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(e) | Excludes net assets of $8 million and $4 million at June 30, 2011 and December 31, 2010, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. |
(f) | The mutual funds |
(g) | Excludes $6 million and $7 million of the cash surrender value of life insurance investments at June 30, 2011 and December 31, 2010, respectively. |
(h) | Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $418 million and $7 million allocated to Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2011. Collateral received from counterparties, net of collateral paid to counterparties, totaled $2 million, $934 million and $15 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2010. |
(i) | The Level 3 balance includes current and noncurrent assets for Generation of $412 million and $345 million at June 30, 2011 and $450 million and $525 million at December 31, 2010, respectively, related to the fair value |
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2011 and June 30, 2010:
Three Months Ended June 30, 2011 | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Total | |||||||||
Balance as of March 31, 2011 | $ | 31 | $ | 933 | $ | 964 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in income | — | 21 | (a) | 21 | ||||||||
Included in other comprehensive income | — | (178 | )(b) | (178 | ) | |||||||
Included in payable for Zion Station decommissioning | 3 | — | 3 | |||||||||
Change in collateral | — | 2 | 2 | |||||||||
Purchases, sales, issuances and settlements | ||||||||||||
Purchases | 12 | 5 | 17 | |||||||||
Sales | (12 | ) | — | (12 | ) | |||||||
Transfers out of Level 3 — Asset | — | (7 | ) | (7 | ) | |||||||
Balance as of June 30, 2011 | $ | 34 | $ | 776 | $ | 810 | ||||||
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended June 30, 2011 | $ | — | $ | 30 | $ | 30 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2011 | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Total | |||||||||
Balance as of December 31, 2010 | $ | — | $ | 1,030 | $ | 1,030 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in income | — | 8 | (a) | 8 | ||||||||
Included in other comprehensive income | — | (233 | )(b) | (233 | ) | |||||||
Included in payable for Zion Station decommissioning | 3 | — | 3 | |||||||||
Change in collateral | — | 7 | 7 | |||||||||
Purchases, sales, issuances and settlements | ||||||||||||
Purchases | 43 | 5 | 48 | |||||||||
Sales | (12 | ) | — | (12 | ) | |||||||
Transfers out of Level 3 — Asset | — | (41 | ) | (41 | ) | |||||||
Balance as of June 30, 2011 | $ | 34 | $ | 776 | $ | 810 | ||||||
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the six months ended June 30, 2011 | $ | — | $ | 23 | $ | 23 |
(a) | Includes the reclassification of $9 million and $15 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2011, respectively. |
(b) | Includes $65 million of decreases in fair value and $2 million of increases in fair value and realized losses reclassified from OCI due to settlements of $108 million and $220 million associated with Generation’s financial swap contract with ComEd and $2 million and $3 million of decreases in fair value due to settlement of Generation’s block contracts with PECO for the three and six months ended June 30, 2011, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements. |
Three Months Ended June 30, 2010 | Nuclear Decommissioning Trust Fund Investments | Mark-to-Market Derivatives | Total | |||||||||
Balance as of March 31, 2010 | $ | — | $ | 1,279 | $ | 1,279 | ||||||
Total realized / unrealized losses | ||||||||||||
Included in other comprehensive income | — | (237 | )(b) | (237 | ) | |||||||
Changes in collateral | — | 9 | 9 | |||||||||
Purchases, sales, issuances and settlements | ||||||||||||
Purchases | 1 | 11 | 12 | |||||||||
Transfers out of Level 3 — Liability | — | 24 | 24 | |||||||||
Balance as of June 30, 2010 | $ | 1 | $ | 1,086 | $ | 1,087 | ||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended June 30, 2010 | $ | — | $ | 1 | $ | 1 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2010 | Nuclear Decommissioning Trust Fund Investments | Mark-to-Market Derivatives | Total | |||||||||
Balance as of December 31, 2009 | $ | — | $ | 931 | $ | 931 | ||||||
Total realized / unrealized gains | ||||||||||||
Included in income | — | 80 | (a) | 80 | ||||||||
Included in other comprehensive income | — | 49 | (b) | 49 | ||||||||
Changes in collateral | — | (8 | ) | (8 | ) | |||||||
Purchases, sales, issuances and settlements | ||||||||||||
Purchases | 1 | 11 | 12 | |||||||||
Transfers out of Level 3 — Liability | — | 23 | 23 | |||||||||
Balance as of June 30, 2010 | $ | 1 | $ | 1,086 | $ | 1,087 | ||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the six months ended June 30, 2010 | $ | — | $ | 78 | $ | 78 |
(a) | Includes the reclassification of $2 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the six months ended June 30, 2010. The reclassification due to settlement of derivative contracts for the three months ended June 30, |
Includes $121 million of decreases in fair value | ||
Nuclear | ||||||||||||||||
Decommissioning | ||||||||||||||||
Servicing | Trust Fund | Mark-to-Market | ||||||||||||||
Three Months Ended June 30, 2009 | Liability | Investments | Derivatives | Total | ||||||||||||
Balance as of March 31, 2009 | $ | (2 | ) | $ | 1,371 | $ | 48 | $ | 1,417 | |||||||
Total realized / unrealized gains (losses) | ||||||||||||||||
Included in income | — | 98 | (33 | )(a) | 65 | |||||||||||
Included in other comprehensive income | — | — | (2 | )(b) | (2 | ) | ||||||||||
Included in regulatory assets | — | 183 | (1 | ) | 182 | |||||||||||
Purchases, sales and issuances, net | — | 27 | — | 27 | ||||||||||||
Balance as of June 30, 2009 | $ | (2 | ) | $ | 1,679 | $ | 12 | $ | 1,689 | |||||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009 | $ | — | $ | 97 | $ | (21 | ) | $ | 76 |
41
Nuclear | ||||||||||||||||
Decommissioning | ||||||||||||||||
Servicing | Trust Fund | Mark-to-Market | ||||||||||||||
Six Months Ended June 30, 2009 | Liability | Investments | Derivatives | Total | ||||||||||||
Balance as of December 31, 2008 | $ | (2 | ) | $ | 1,220 | $ | 106 | $ | 1,324 | |||||||
Total realized / unrealized gains (losses) | ||||||||||||||||
Included in income | — | 41 | (101 | )(a) | (60 | ) | ||||||||||
Included in other comprehensive income | — | — | 10 | (b) | 10 | |||||||||||
Included in regulatory assets | — | 84 | (1 | ) | 83 | |||||||||||
Purchases, sales and issuances, net | — | 334 | — | 334 | ||||||||||||
Transfers into (out of ) Level 3 | — | — | (2 | ) | (2 | ) | ||||||||||
Balance as of June 30, 2009 | $ | (2 | ) | $ | 1,679 | $ | 12 | $ | 1,689 | |||||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009 | $ | — | $ | 40 | $ | (71 | ) | $ | (31 | ) |
Operating | Purchased | |||||||||||||||
Revenue | Power | Fuel | Other, net | |||||||||||||
Total gains (losses) included in income for the three months ended June 30, 2010 | $ | 15 | $ | (20 | ) | $ | 5 | $ | — | |||||||
Total gains included in income for the six months ended June 30, 2010 | $ | 13 | $ | 36 | $ | 31 | $ | 2 | ||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2010 for the three months ended June 30, 2010 | $ | 20 | $ | (21 | ) | $ | 2 | $ | — | |||||||
Change in the unrealized gains relating to assets and liabilities held as of June 30, 2010 for the six months ended June 30, 2010 | $ | 23 | $ | 33 | $ | 22 | $ | — |
Operating | Purchased | |||||||||||||||
Revenue | Power | Fuel | Other, net | |||||||||||||
Total gains (losses) included in income for the three months ended June 30, 2009 | $ | (21 | ) | $ | (10 | ) | $ | (2 | ) | $ | 98 | |||||
Total gains (losses) included in income for the six months ended June 30, 2009 | $ | (42 | ) | $ | (6 | ) | $ | (53 | ) | $ | 41 | |||||
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2009 for the three months ended June 30, 2009 | $ | — | $ | (9 | ) | $ | (12 | ) | $ | 97 | ||||||
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2009 for the six months ended June 30, 2009 | $ | — | $ | (7 | ) | $ | (64 | ) | $ | 40 |
Operating Revenue | Purchased Power | Fuel | ||||||||||
Total gains included in income for the three months ended June 30, 2011 | $ | 10 | $ | 10 | $ | 1 | ||||||
Total gains (losses) included in income for the six months ended June 30, 2011 | $ | 7 | $ | 3 | $ | (2 | ) | |||||
Change in the unrealized gains relating to assets and liabilities held for the three months ended June 30, 2011 | $ | 17 | $ | 11 | $ | 2 | ||||||
Change in the unrealized gains relating to assets and liabilities held for the six months ended June 30, 2011 | $ | 21 | $ | 2 | $ | — |
42
Operating Revenue | Purchased Power | Fuel | ||||||||||
Total gains (losses) included in income for the three months ended June 30, 2010 | $ | 15 | $ | (20 | ) | $ | 5 | |||||
Total gains included in income for the six months ended June 30, 2010 | $ | 13 | $ | 36 | $ | 31 | ||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended June 30, 2010 | $ | 20 | $ | (21 | ) | $ | 2 | |||||
Change in the unrealized gains relating to assets and liabilities held for the six months ended June 30, 2010 | $ | 23 | $ | 33 | $ | 22 |
(Dollars in millions, except per share data, unless otherwise noted)
As of June 30, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 790 | $ | — | $ | — | $ | 790 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 53 | 73 | — | 126 | ||||||||||||
Equity securities(b) | 1,414 | — | — | 1,414 | ||||||||||||
Commingled funds(c) | — | 1,920 | — | 1,920 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 702 | 106 | — | 808 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 440 | — | 440 | ||||||||||||
Corporate debt securities | — | 719 | — | 719 | ||||||||||||
Federal agency mortgage-backed securities | — | 761 | — | 761 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 125 | — | 125 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 8 | — | 8 | ||||||||||||
Other debt obligations | — | 74 | 1 | 75 | ||||||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 2,169 | 4,226 | 1 | 6,396 | ||||||||||||
Rabbi trust investments(e)(f) | 4 | — | — | 4 | ||||||||||||
Mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 973 | 1,019 | 1,992 | ||||||||||||
Other derivatives | 3 | 1,837 | 72 | 1,912 | ||||||||||||
Proprietary trading | — | 287 | 47 | 334 | ||||||||||||
Effect of netting and allocation of collateral received/paid (g) | (6 | ) | (2,154 | ) | (33 | ) | (2,193 | ) | ||||||||
Mark-to-market assets(h) | (3 | ) | 943 | 1,105 | 2,045 | |||||||||||
Total assets | 2,960 | 5,169 | 1,106 | 9,235 | ||||||||||||
Liabilities | ||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges | — | (73 | ) | (3 | ) | (76 | ) | |||||||||
Other derivatives | (3 | ) | (948 | ) | (25 | ) | (976 | ) | ||||||||
Proprietary trading | — | (282 | ) | (13 | ) | (295 | ) | |||||||||
Effect of netting and allocation of collateral received/paid (g) | 3 | 1,270 | 22 | 1,295 | ||||||||||||
Mark-to-market liabilities | — | (33 | ) | (19 | ) | (52 | ) | |||||||||
Deferred compensation | — | (19 | ) | — | (19 | ) | ||||||||||
Total liabilities | — | (52 | ) | (19 | ) | (71 | ) | |||||||||
Total net assets | $ | 2,960 | $ | 5,117 | $ | 1,087 | $ | 9,164 | ||||||||
43
As of December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 1,040 | $ | — | $ | — | $ | 1,040 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 2 | 120 | — | 122 | ||||||||||||
Equity securities(b) | 1,528 | — | — | 1,528 | ||||||||||||
Commingled funds(c) | — | 2,086 | — | 2,086 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 511 | 119 | — | 630 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 454 | — | 454 | ||||||||||||
Corporate debt securities | — | 710 | — | 710 | ||||||||||||
Federal agency mortgage-backed securities | — | 887 | — | 887 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 91 | — | 91 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 9 | — | 9 | ||||||||||||
Other debt obligations | — | 76 | — | 76 | ||||||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 2,041 | 4,552 | — | 6,593 | ||||||||||||
Rabbi trust investments(e)(f) | 4 | — | — | 4 | ||||||||||||
Mark-to-market derivative net assets(g)(h) | (4 | ) | 842 | 931 | 1,769 | |||||||||||
Total assets | 3,081 | 5,394 | 931 | 9,406 | ||||||||||||
Liabilities | ||||||||||||||||
Deferred compensation | — | (23 | ) | — | (23 | ) | ||||||||||
Total liabilities | — | (23 | ) | — | (23 | ) | ||||||||||
Total net assets | $ | 3,081 | $ | 5,371 | $ | 931 | $ | 9,383 | ||||||||
Nuclear | ||||||||||||
Decommissioning | ||||||||||||
Trust Fund | Mark-to-Market | |||||||||||
Three Months Ended June 30, 2010 (a) | Investments | Derivatives | Total | |||||||||
Balance as of March 31, 2010 | $ | — | $ | 1,279 | $ | 1,279 | ||||||
Total realized / unrealized losses | ||||||||||||
Included in other comprehensive income | — | (237 | )(c) | (237 | ) | |||||||
Change in collateral | — | 9 | 9 | |||||||||
Purchases, sales, issuances, and settlements | ||||||||||||
Purchases | 1 | 11 | 12 | |||||||||
Transfers out of Level 3 — Liability | — | 24 | 24 | |||||||||
Balance as of June 30, 2010 | $ | 1 | $ | 1,086 | $ | 1,087 | ||||||
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held as of June 30, 2010 | $ | — | $ | 1 | $ | 1 |
44
Nuclear | ||||||||||||
Decommissioning | ||||||||||||
Trust Fund | Mark-to-Market | |||||||||||
Six Months Ended June 30, 2010 (a) | Investments | Derivatives | Total | |||||||||
Balance as of December 31, 2009 | $ | — | $ | 931 | $ | 931 | ||||||
Total realized / unrealized gains | ||||||||||||
Included in income | — | 80 | (b) | 80 | ||||||||
Included in other comprehensive income | — | 49 | (c) | 49 | ||||||||
Change in collateral | — | (8 | ) | (8 | ) | |||||||
Purchases, sales, issuances, and settlements | ||||||||||||
Purchases | 1 | 11 | 12 | |||||||||
Transfers out of Level 3 — Liability | — | 23 | 23 | |||||||||
Balance as of June 30, 2010 | $ | 1 | $ | 1,086 | $ | 1,087 | ||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2010 | $ | — | $ | 78 | $ | 78 |
Nuclear | ||||||||||||
Decommissioning | ||||||||||||
Trust Fund | Mark-to-Market | |||||||||||
Three Months Ended June 30, 2009 | Investments | Derivatives | Total | |||||||||
Balance as of March 31, 2009 | $ | 1,371 | $ | 1,230 | $ | 2,601 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in income | 98 | (33 | )(a) | 65 | ||||||||
Included in other comprehensive income | — | (146 | )(b) | (146 | ) | |||||||
Included in noncurrent payables to affiliates | 183 | — | 183 | |||||||||
Purchases, sales, issuances and settlements, net | 27 | — | 27 | |||||||||
Balance as of June 30, 2009 | $ | 1,679 | $ | 1,051 | $ | 2,730 | ||||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009 | $ | 97 | $ | (21 | ) | $ | 76 |
Nuclear | ||||||||||||
Decommissioning | ||||||||||||
Trust Fund | Mark-to-Market | |||||||||||
Six Months Ended June 30, 2009 | Investments | Derivatives | Total | |||||||||
Balance as of December 31, 2008 | $ | 1,220 | $ | 562 | $ | 1,782 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in income | 41 | (101 | )(a) | (60 | ) | |||||||
Included in other comprehensive income | — | 592 | (b) | 592 | ||||||||
Included in noncurrent payables to affiliates | 84 | — | 84 | |||||||||
Purchases, sales, issuances and settlements, net | 334 | — | 334 | |||||||||
Transfers out of Level 3 | — | (2 | ) | (2 | ) | |||||||
Balance as of June 30, 2009 | $ | 1,679 | $ | 1,051 | $ | 2,730 | ||||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009 | $ | 40 | $ | (71 | ) | $ | (31 | ) |
45
Operating | Purchased | |||||||||||||||
Revenue | Power | Fuel | Other, net | |||||||||||||
Total gains (losses) included in income for the three months ended June 30, 2010 | $ | 15 | $ | (20 | ) | $ | 5 | $ | — | |||||||
Total gains included in income for the six months ended June 30, 2010 | $ | 13 | $ | 36 | $ | 31 | $ | — | ||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2010 for the three months ended June 30, 2010 | $ | 20 | $ | (21 | ) | $ | 2 | $ | — | |||||||
Change in the unrealized gains relating to assets and liabilities held as of June 30, 2010 for the six months ended June 30, 2010 | $ | 23 | $ | 33 | $ | 22 | $ | — |
Operating | Purchased | |||||||||||||||
Revenue | Power | Fuel | Other, net | |||||||||||||
Total gains (losses) included in income for the three months ended June 30, 2009 | $ | (21 | ) | $ | (10 | ) | $ | (2 | ) | $ | 98 | |||||
Total gains (losses) included in income for the six months ended June 30, 2009 | $ | (42 | ) | $ | (6 | ) | $ | (53 | ) | $ | 41 | |||||
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2009 for the three months ended June 30, 2009 | $ | — | $ | (9 | ) | $ | (12 | ) | $ | 97 | ||||||
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2009 for the six months ended June 30, 2009 | $ | — | $ | (7 | ) | $ | (64 | ) | $ | 40 |
The following tables present assets and liabilities measured and recorded at fair value on ComEd’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 20102011 and December 31, 2009:
As of June 30, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents (a) | $ | 7 | $ | — | $ | — | $ | 7 | ||||||||
Rabbi trust investments | ||||||||||||||||
Cash equivalents | 24 | — | — | 24 | ||||||||||||
Total assets | 31 | — | — | 31 | ||||||||||||
Liabilities | ||||||||||||||||
Deferred compensation obligation | — | (7 | ) | — | (7 | ) | ||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges (b) | — | (6 | ) | — | (6 | ) | ||||||||||
Other derivatives (c) | — | — | (1,010 | ) | (1,010 | ) | ||||||||||
Mark-to-market liabilities | — | (6 | ) | (1,010 | ) | (1,016 | ) | |||||||||
Total liabilities | — | (13 | ) | (1,010 | ) | (1,023 | ) | |||||||||
Total net assets (liabilities) | $ | 31 | $ | (13 | ) | $ | (1,010 | ) | $ | (992 | ) | |||||
As of June 30, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 33 | $ | — | $ | — | $ | 33 | ||||||||
Rabbi trust investments | ||||||||||||||||
Mutual funds | 22 | — | — | 22 | ||||||||||||
Total assets | 55 | — | — | 55 | ||||||||||||
Liabilities | ||||||||||||||||
Deferred compensation obligation | — | (8 | ) | — | (8 | ) | ||||||||||
Mark-to-market derivative liabilities(b)(c) | — | — | (788 | ) | (788 | ) | ||||||||||
Total liabilities | — | (8 | ) | (788 | ) | (796 | ) | |||||||||
Total net assets (liabilities) | $ | 55 | $ | (8 | ) | $ | (788 | ) | $ | (741 | ) | |||||
46
As of December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 1 | $ | — | $ | — | $ | 1 | ||||||||
Rabbi trust investments | ||||||||||||||||
Mutual funds | 23 | — | — | 23 | ||||||||||||
Rabbi trust investment subtotal | 23 | — | — | 23 | ||||||||||||
Mark-to-market derivative assets | — | — | 4 | 4 | ||||||||||||
Total assets | 24 | — | 4 | 28 | ||||||||||||
Liabilities | ||||||||||||||||
Deferred compensation obligation | — | (8 | ) | — | (8 | ) | ||||||||||
Mark-to-market derivative liabilities(b) | — | — | (975 | ) | (975 | ) | ||||||||||
Total liabilities | — | (8 | ) | (975 | ) | (983 | ) | |||||||||
�� | ||||||||||||||||
Total net assets (liabilities) | $ | 24 | $ | (8 | ) | $ | (971 | ) | $ | (955 | ) | |||||
As of December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents (a) | $ | 25 | $ | — | $ | — | $ | 25 | ||||||||
Rabbi trust investments | ||||||||||||||||
Cash equivalents | 28 | — | — | 28 | ||||||||||||
Total assets | 53 | — | — | 53 | ||||||||||||
Liabilities | ||||||||||||||||
Deferred compensation obligation | — | (8 | ) | — | (8 | ) | ||||||||||
Mark-to-market derivative liabilities (c) | — | — | (971 | ) | (971 | ) | ||||||||||
Total liabilities | — | (8 | ) | (971 | ) | (979 | ) | |||||||||
Total net assets (liabilities) | $ | 53 | $ | (8 | ) | $ | (971 | ) | $ | (926 | ) | |||||
(a) | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |
(b) | ||
The Level 3 balance |
(c) | The Level 3 balance includes the current and noncurrent liability of $1 million and $30 million at June 30, 2011, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. The current liability is included in other current liabilities in ComEd’s Consolidated Balance Sheets. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 20102011 and 2009:
Mark-to-Market | ||||
Three Months Ended June 30, 2010 | Derivatives | |||
Balance as of March 31, 2010 | $ | (1,235 | ) | |
Total realized / unrealized gains included in regulatory assets (a) | 225 | |||
Balance as of June 30, 2010 | $ | (1,010 | ) | |
Mark-to-Market | ||||
Six Months Ended June 30, 2010 | Derivatives | |||
Balance as of December 31, 2009 | $ | (971 | ) | |
Total realized / unrealized losses included in regulatory assets (a) | (39 | ) | ||
Balance as of June 30, 2010 | $ | (1,010 | ) | |
Three Months Ended June 30, 2011 | Mark-to-Market Derivatives | |||
Balance as of March 31, 2011 | $ | (875 | ) | |
Total realized / unrealized gains included in regulatory assets(a)(b) | 87 | |||
Balance as of June 30, 2011 | $ | (788 | ) | |
Six Months Ended June 30, 2011 | Mark-to-Market Derivatives | |||
Balance as of December 31, 2010 | $ | (971 | ) | |
Total realized / unrealized gains included in regulatory assets(a)(b) | 183 | |||
Balance as of June 30, 2011 | $ | (788 | ) | |
(a) | Includes |
(b) | Includes $86 million and $35 million of decreases in the fair value of floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and six months ended June 30, 2011, respectively. |
Three Months Ended June 30, 2010 | Mark-to-Market Derivatives | |||
Balance as of March 31, 2010 | $ | (1,235 | ) | |
Total realized / unrealized gains included in regulatory assets(a) | 225 | |||
Balance as of June 30, 2010 | $ | (1,010 | ) | |
Six Months Ended June 30, 2010 | Mark-to-Market Derivatives | |||
Balance as of December 31, 2009 | $ | (971 | ) | |
Total realized / unrealized losses included in regulatory assets(a) | (39 | ) | ||
Balance as of June 30, 2010 | $ | (1,010 | ) | |
(a) | Includes $121 million of increases in fair value and |
Mark-to-Market | ||||
Three Months Ended June 30, 2009 | Derivatives | |||
Balance as of March 31, 2009 | $ | (1,182 | ) | |
Total realized / unrealized gains included in regulatory assets (a) | 145 | |||
Balance as of June 30, 2009 | $ | (1,037 | ) | |
Mark-to-Market | ||||
Six Months Ended June 30, 2009 | Derivatives | |||
Balance as of December 31, 2008 | $ | (456 | ) | |
Total realized / unrealized losses included in regulatory assets (a) | (581 | ) | ||
Balance as of June 30, 2009 | $ | (1,037 | ) | |
47
(Dollars in millions, except per share data, unless otherwise noted)
PECO
The following tables present assets and liabilities measured and recorded at fair value on PECO’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 20102011 and December 31, 2009:
As of June 30, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 612 | $ | — | $ | — | $ | 612 | ||||||||
Rabbi trust investments — mutual funds(b)(c) | 7 | — | — | 7 | ||||||||||||
Total assets | 619 | — | — | 619 | ||||||||||||
Liabilities | ||||||||||||||||
Deferred compensation obligation | — | (22 | ) | — | (22 | ) | ||||||||||
Mark-to-market derivative liabilities(d) | — | — | (9 | ) | (9 | ) | ||||||||||
Total liabilities | — | (22 | ) | (9 | ) | (31 | ) | |||||||||
Total net assets (liabilities) | $ | 619 | $ | (22 | ) | $ | (9 | ) | $ | 588 | ||||||
As of December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 281 | $ | — | $ | — | $ | 281 | ||||||||
Rabbi trust investments — mutual funds(b)(c) | 7 | — | — | 7 | ||||||||||||
Total assets | 288 | — | — | 288 | ||||||||||||
Liabilities | ||||||||||||||||
Deferred compensation obligation | — | (25 | ) | — | (25 | ) | ||||||||||
Mark-to-market derivative liabilities(d) | — | — | (4 | ) | (4 | ) | ||||||||||
Servicing liability | — | — | (2 | ) | (2 | ) | ||||||||||
Total liabilities | — | (25 | ) | (6 | ) | (31 | ) | |||||||||
Total net assets (liabilities) | $ | 288 | $ | (25 | ) | $ | (6 | ) | $ | 257 | ||||||
As of June 30, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents | $ | 298 | $ | — | $ | — | $ | 298 | ||||||||
Rabbi trust investments — mutual funds(b)(c) | 8 | — | — | 8 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total assets | 306 | — | — | 306 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Liabilities | ||||||||||||||||
Deferred compensation obligation | — | (21 | ) | — | (21 | ) | ||||||||||
Mark-to-market derivative liabilities(d) | — | — | (4 | ) | (4 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total liabilities | — | (21 | ) | (4 | ) | (25 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Total net assets (liabilities) | $ | 306 | $ | (21 | ) | $ | (4 | ) | $ | 281 | ||||||
|
|
|
|
|
|
|
|
As of December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 499 | $ | — | $ | — | $ | 499 | ||||||||
Rabbi trust investments — mutual funds(b)(c) | 7 | — | — | 7 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total assets | 506 | — | — | 506 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Liabilities | ||||||||||||||||
Deferred compensation obligation | — | (23 | ) | — | (23 | ) | ||||||||||
Mark-to-market derivative liabilities(d) | — | — | (9 | ) | (9 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total liabilities | — | (23 | ) | (9 | ) | (32 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Total net assets (liabilities) | $ | 506 | $ | (23 | ) | $ | (9 | ) | $ | 474 | ||||||
|
|
|
|
|
|
|
|
(a) | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |
(b) | The mutual funds held by the Rabbi trusts invest in common stock of | |
(c) | Excludes | |
(d) | The Level 3 |
48
Mark-to-Market | ||||
Three Months Ended June 30, 2010 | Derivatives | |||
Balance as of March 31, 2010 | $ | (11 | ) | |
Total unrealized gains included in regulatory assets | 2 | (b) | ||
Balance as of June 30, 2010 | $ | (9 | ) | |
Mark-to-Market | ||||||||||||
Six Months Ended June 30, 2010 | Derivatives | Servicing Liability | Total | |||||||||
Balance as of December 31, 2009 | $ | (4 | ) | $ | (2 | ) | $ | (6 | ) | |||
Total realized / unrealized gains (losses) | ||||||||||||
Included in net income | — | 2 | (a) | 2 | ||||||||
Included in regulatory assets | (5 | )(b) | — | (5 | ) | |||||||
Balance as of June 30, 2010 | $ | (9 | ) | $ | — | $ | (9 | ) | ||||
Three Months Ended June 30, 2011 | Mark-to-Market Derivatives | |||||||
Balance as of March 31, 2011 | $ | (7 | ) | |||||
Total realized gains included in regulatory assets | 3 | (a) | ||||||
|
| |||||||
Balance as of June 30, 2011 | $ | (4 | ) | |||||
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2011 | Mark-to-Market Derivatives | |||
Balance as of December 31, 2010 | $ | (9 | ) | |
Total realized gains included in regulatory assets | 5 | (a) | ||
|
| |||
Balance as of June 30, 2011 | $ | (4 | ) | |
|
|
(a) | Includes increases of $2 million and $3 million related to the settlement of PECO’s block contract with Generation for the three and six months ended June 30, 2011, respectively, which eliminate upon consolidation in Exelon’s Consolidated Financial Statements. |
Three Months Ended June 30, 2010 | Mark-to-Market Derivatives | |||||||||||
Balance as of March 31, 2010 | $ | (11 | ) | |||||||||
Total unrealized gains included in regulatory assets | 2 | (b) | ||||||||||
|
| |||||||||||
Balance as of June 30, 2010 | $ | (9 | ) | |||||||||
|
| |||||||||||
Six Months Ended June 30, 2010 | Mark-to-Market Derivatives | Servicing Liability | Total | |||||||||
Balance as of December 31, 2009 | $ | (4 | ) | $ | (2 | ) | $ | (6 | ) | |||
Total realized / unrealized gains (losses) | ||||||||||||
Included in net income | — | 2 | (a) | 2 | ||||||||
Included in regulatory assets | (5 | )(b) | — | (5 | ) | |||||||
|
|
|
|
|
| |||||||
Balance as of June 30, 2010 | $ | (9 | ) | $ | — | $ | (9 | ) | ||||
|
|
|
|
|
|
(a) | The servicing liability related to PECO’s accounts receivable agreement was released in accordance with new guidance on accounting for transfers of financial assets that was adopted on January 1, 2010. |
(b) | Includes |
Mark-to-Market | ||||||||||||
Three Months Ended June 30, 2009 | Derivatives | Servicing Liability | Total | |||||||||
Balance as of March 31, 2009 | $ | — | $ | (2 | ) | $ | (2 | ) | ||||
Total unrealized losses included in regulatory assets | (2 | ) | — | (2 | ) | |||||||
Balance as of June 30, 2009 | $ | (2 | ) | $ | (2 | ) | $ | (4 | ) | |||
Mark-to-Market | ||||||||||||
Six Months Ended June 30, 2009 | Derivatives | Servicing Liability | Total | |||||||||
Balance as of December 31, 2008 | $ | — | $ | (2 | ) | $ | (2 | ) | ||||
Total unrealized losses included in regulatory assets | (2 | ) | — | (2 | ) | |||||||
Balance as of June 30, 2009 | $ | (2 | ) | $ | (2 | ) | $ | (4 | ) | |||
Valuation Techniques Used to Determine Fair Value
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.
Cash Equivalents (Exelon, Generation, ComEd and PECO).The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation).The trust fund investments have been established to satisfy Exelon’s and Generation’s nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation’s investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies restrict the trust funds from holding alternative investments and limit the trust funds’ exposures to investments in highly illiquid markets. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities, are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.
49
Commingled funds, which are similar to mutual funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of short-term commingled funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. In general, equity commingled funds are redeemable on the 15th of the month and the last business day of the month; however, the fund manager may designate any day as a valuation date for the purpose of purchasing or redeeming units. Effective December 31, 2009, commingledCommingled funds are categorized in Level 2 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets on the underlying equity securities. See Note 109 — Nuclear Decommissioning for further discussion on the NDT fund investments.
Rabbi Trust Investments (Exelon, Generation, ComEd and PECO).The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The investments in the Rabbi trusts are included in investments in the Registrants’ Consolidated Balance Sheets. The fair values of the shares of the funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.
Mark-to-Market Derivatives (Exelon, Generation, ComEd and PECO).Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based derivatives are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of non-exchange-based derivative contracts is valued using the Black model, an industry standard option valuation
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For non-exchange-based derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ non-exchange-based derivatives are predominately at liquid trading points. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, such as the financial swap contract between Generation and ComEd, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements. Transfers in and out of levels are recognized as of the beginning of the month the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between levelLevel 2 and levelLevel 1 generally do not occur. Transfers in and out of levelLevel 2 and levelLevel 3 generally occur when the contract tenure becomes more observable.
50
Deferred Compensation Obligations (Exelon, Generation, ComEd and PECO).The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized in Level 2 in the fair value hierarchy.
Servicing Liability (Exelon and PECO).PECO is party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in customer accounts receivables designated under the agreement in exchange for proceeds of $225 million, which PECO accounted for as a sale under previous guidance on accounting for transfers of financial assets. A servicing liability was recorded for the agreement in accordance with the applicable authoritative guidance for servicing of financial assets. The servicing liability was included in other current liabilities in Exelon’s and PECO’s Consolidated Balance Sheets. The fair value of the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
liability was determined using internal estimates based on provisions in the agreement, which were categorized as Level 3 inputs in the fair value hierarchy. The servicing liability was released in accordance with new guidance on accounting for transfers of financial assets that was adopted on January 1, 2010.
6. Derivative Financial Instruments (Exelon, Generation, ComEd and PECO)
The Registrants are exposed to certain risks related to ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations by entering into physical contracts as well as financial derivative contracts including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt, commercial paper and lines of credit.
Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value. Under these provisions, economic hedges are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and normal sales exception. The Registrants have applied the normal purchases and normal sales scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. For economic hedges that qualify and are designated as cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. For economic hedges that do not qualify or are not designated as cash flow hedges, changes in the fair value of the derivative are recognized in earnings each period and are classified as other derivatives in the following tables. Non-derivative contracts for access to additional generation and for sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 18 of the 2010 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.
Commodity Price Risk (Exelon, Generation, ComEd and PECO)
Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases, and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity risk on a ratable basis over three-year periods. As of June 30, 2011, the percentage of expected generation hedged was 95%-98%, 82%-85%, and 49%-52% for 2011, 2012 and 2013, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load.
ComEd has locked in a fixed price for a significant portion of its commodity price risk through the five-year financial swap contract with Generation that expires on May 31, 2013, which is discussed in more detail below. In addition, the contracts that Generation has entered into with ComEd and that ComEd has entered into with Generation and other suppliers as part of the ComEd power procurement agreements, which are further discussed in Note 2 of the 2010 Form 10-K, qualify for the normal purchases and normal sales scope exception. Based on the Illinois Settlement Legislation and ICC-approved procurement methodologies permitting ComEd to recover its electricity procurement costs from retail customers with no mark-up, ComEd’s price risk related to power procurement is limited.
In order to fulfill a requirement of the Illinois Settlement Legislation, Generation and ComEd entered into a five-year financial swap contract effective August 28, 2007. The financial swap is designed to hedge spot market purchases, which, along with ComEd’s remaining energy procurement contracts, meet its load service requirements. The remaining swap contract volume is 3,000 MWs through May 2013. The terms of the financial swap contract require Generation to pay the around-the-clock market price for a portion of ComEd’s electricity supply requirement, while ComEd pays a fixed price. The contract is to be settled net, for the difference between the fixed and market pricing, and the financial terms only cover energy costs and do not cover capacity or ancillary services. The financial swap contract is a derivative financial instrument that has been designated by Generation as a cash flow hedge. Consequently, Generation records the fair value of the swap on its balance sheet and records changes in fair value to OCI. ComEd has not elected hedge accounting for this derivative financial instrument. ComEd records the fair value of the swap on its balance sheet, however, since the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates and the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 5 — Debt and Credit Agreements2 of the 2010 Form 10-K for additional information regarding the Illinois Settlement Legislation. In Exelon’s consolidated financial statements, all financial statement effects of the financial swap recorded by Generation and ComEd are eliminated.
On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts begins in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability.
PECO has contracts to procure electric supply that were executed through the competitive RFP process outlined in its PAPUC-approved DSP Program, which is further discussed in Note 3—Regulatory Matters. Based on Pennsylvania legislation and the DSP Program permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
contracts and block contracts. PECO’s full requirements contracts and block contracts, which are considered derivatives, qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. For block contracts designated as normal purchases after inception, the mark-to-market balances previously recorded on PECO’s Consolidated Balance Sheet are being amortized over the terms of the contracts, which began on January 1, 2011.
PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives qualify for the normal purchases and normal sales scope exception and have been designated as such. Additionally, in accordance with the 2010 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2010 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program covers 22% to 29% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.
Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure and is subject to limits established by Exelon’s RMC. The proprietary trading activities, which included volumes of 1,496 GWh and 2,829 GWh for the three and six months ended June 30, 2011, respectively, and 889 GWh and 1,808 GWh for the three and six months ended June 30, 2010, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. Neither ComEd nor PECO enter into derivatives for proprietary trading purposes.
Interest Rate Risk (Exelon, Generation, ComEd and PECO)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in each of Exelon’s, ComEd’s and PECO’s pre-tax income for the three months ended June 30, 2011.
Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:
Income Statement Classification | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | ||||||||||||||
Six Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Interest expense | $ | — | $ | 5 | $ | — | $ | (5 | ) |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
At June 30, 2011 and December 31, 2010, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $14 million and $14 million, respectively, which expire in 2015. During the three and six months ended June 30, 2011 and 2010, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.
Fair Value Measurement (Exelon, Generation, ComEd and PECO)
Fair value accounting guidance requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. In the table below, Generation’s cash flow hedges, other derivatives and proprietary trading derivatives are shown gross and the impact of the netting of fair value balances with the same counterparty, as well as netting of collateral, is aggregated in the collateral and netting column. Excluded from the tables below are economic hedges that qualify for the normal purchases and normal sales scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of June 30, 2011:
Generation | ComEd | PECO | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Derivatives | Cash Flow Hedges (a)(d) | Other Derivatives | Proprietary Trading | Collateral and Netting (b) | Subtotal (c) | Other Derivatives (a)(e) | Other Derivatives (d) | Other Derivatives | Intercompany Eliminations (a)(d) | Total Derivatives | ||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 335 | $ | 841 | $ | 173 | $ | (911 | ) | $ | 438 | $ | — | $ | — | $ | — | $ | — | $ | 438 | |||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 414 | — | — | — | 414 | — | — | — | (414 | ) | — | |||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 148 | 399 | 60 | (297 | ) | 310 | — | — | 14 | — | 324 | |||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 345 | — | — | — | 345 | — | — | — | (345 | ) | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,242 | $ | 1,240 | $ | 233 | $ | (1,208 | ) | $ | 1,507 | $ | — | $ | — | $ | 14 | $ | (759 | ) | $ | 762 | ||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (46 | ) | $ | (452 | ) | $ | (150 | ) | $ | 601 | $ | (47 | ) | $ | (1 | ) | $ | (2 | ) | $ | — | $ | — | $ | (50 | ) | |||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (412 | ) | (2 | ) | — | 414 | — | ||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (50 | ) | (119 | ) | (49 | ) | 182 | (36 | ) | (30 | ) | — | — | — | (66 | ) | ||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (345 | ) | — | — | 345 | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (96 | ) | (571 | ) | (199 | ) | 783 | (83 | ) | (788 | ) | (4 | ) | — | 759 | (116 | ) | |||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 1,146 | $ | 669 | $ | 34 | $ | (425 | ) | $ | 1,424 | $ | (788 | ) | $ | (4 | ) | $ | 14 | $ | — | $ | 646 | |||||||||||||||||
(a) | Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $412 million and $345 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. |
(b) | Represents the netting of fair value balances with the same counterparty and the application of collateral. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(c) | Current and noncurrent assets are shown net of collateral of $300 million and $92 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $9 million and $24 million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $425 million at June 30, 2011. |
(d) | Includes current assets for Generation and current liabilities for PECO of $2 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of June 30, 2011. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in fair value of PECO’s block contracts were recorded and the mark-to-market balances previously recorded are being amortized over the terms of the contracts. |
(e) | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2010:
Generation | ComEd | PECO | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Derivatives | Cash Flow Hedges (a)(d) | Other Derivatives | Proprietary Trading | Collateral and Netting (b) | Subtotal (c) | Other Derivatives (a)(e) | Other Derivatives (d) | Other Derivatives | Intercompany Eliminations (a)(d) | Total Derivatives | ||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 532 | $ | 1,203 | $ | 225 | $ | (1,473 | ) | $ | 487 | $ | — | $ | — | $ | — | $ | — | $ | 487 | |||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 455 | — | — | — | 455 | — | — | — | (455 | ) | — | |||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 204 | 547 | 56 | (416 | ) | 391 | 4 | — | 14 | — | 409 | |||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 525 | — | — | — | 525 | — | — | — | (525 | ) | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,716 | $ | 1,750 | $ | 281 | $ | (1,889 | ) | $ | 1,858 | $ | 4 | $ | — | $ | 14 | $ | (980 | ) | $ | 896 | ||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (21 | ) | $ | (551 | ) | $ | (200 | ) | $ | 738 | $ | (34 | ) | $ | — | $ | (4 | ) | $ | — | $ | — | $ | (38 | ) | ||||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (450 | ) | (5 | ) | — | 455 | — | ||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (24 | ) | (143 | ) | (54 | ) | 200 | (21 | ) | — | — | — | — | (21 | ) | |||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (525 | ) | — | — | 525 | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (45 | ) | (694 | ) | (254 | ) | 938 | (55 | ) | (975 | ) | (9 | ) | — | 980 | (59 | ) | |||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 1,671 | $ | 1,056 | $ | 27 | $ | (951 | ) | $ | 1,803 | $ | (971 | ) | $ | (9 | ) | $ | 14 | $ | — | $ | 837 | |||||||||||||||||
(a) | Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $450 million and $525 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. |
(b) | Represents the netting of fair value balances with the same counterparty and the application of collateral. |
(c) | Current and noncurrent assets are shown net of collateral of $725 million and $199 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $10 million and $17 million, respectively. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $951 million at December 31, 2010. |
(d) | Includes current assets for Generation and current liabilities for PECO of $5 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of December 31, 2010. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in the fair value of PECO’s block contracts were recorded. Previously recorded mark-to-market-balances are being amortized over the term of the contract. |
(e) | Includes noncurrent assets relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Cash Flow Hedges (Exelon, Generation and ComEd). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At June 30, 2011, Generation had net unrealized pre-tax gains on effective cash flow hedges of $ 1,135 million being deferred within accumulated OCI, including $757 million related to the financial swap with ComEd. Amounts recorded in accumulated OCI related to changes in energy commodity cash flow hedges are reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs. Reclassifications from OCI are included in operating revenues, purchased power and fuel in Exelon’s and Generation’s Consolidated Statements of Operations, depending on the commodities involved in the hedged transaction. Based on market prices at June 30, 2011, approximately $699 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation, including approximately $412 million related to the financial swap with ComEd. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices. Generation expects the settlement of the majority of its cash flow hedges, including the ComEd financial swap contract, will occur during 2011 through 2013.
Exelon discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item, in the case of forward-starting hedges, or when it is no longer probable that the forecasted transaction will occur. For the three months ended June 30, 2011 and 2010, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial.
The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and six months ended June 30, 2011 and 2010, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Three Months Ended June 30, 2011 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at March 31, | $ | 941 | (a) | $ | 354 | |||||
Effective portion of changes in fair value | (106 | )(b) | (64 | ) | ||||||
Reclassifications from accumulated OCI to | Operating Revenue | (143 | )(c) | (77 | ) | |||||
Ineffective portion recognized in income | Purchased Power | (4 | ) | (4 | ) | |||||
Accumulated OCI derivative gain at June 30, | $ | 688 | (a)(d) | $ | 209 | |||||
(a) | Includes $458 million and $562 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $2 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and March 31, 2011, respectively. |
(b) | Includes $39 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract. |
(c) | Includes a $65 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the three months ended June 30, 2011. |
(d) | Excludes $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Six Months Ended June 30, 2011 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at December 31, 2010 | $ | 1,011 | (a) | $ | 400 | |||||
Effective portion of changes in fair value | (43 | )(b) | (46 | ) | ||||||
Reclassifications from accumulated OCI to | Operating Revenue | (275 | )(c) | (140 | ) | |||||
Ineffective portion recognized in income | Purchased Power | (5 | ) | (5 | ) | |||||
Accumulated OCI derivative gain at June 30, | $ | 688 | (a)(d) | $ | 209 | |||||
(a) | Includes $458 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and December 31, 2010. |
(b) | Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the six months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract. |
(c) | Includes a $133 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd and a $2 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the six months ended June 30, 2011. |
(d) | Excludes $2 million of gains, net of taxes, related to interest rate swaps. |
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Three Months Ended June 30, 2010 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at March 31, 2010 | $ | 1,703 | (a) | $ | 934 | |||||
Effective portion of changes in fair value | (335 | )(b) | (262 | ) | ||||||
Reclassifications from accumulated OCI to net income | Operating Revenue | (211 | )(c) | (148 | ) | |||||
Ineffective portion recognized in income | Purchased Power | 1 | 1 | (e) | ||||||
Accumulated OCI derivative gain at June 30, 2010 | $ | 1,158 | (a)(d) | $ | 525 | |||||
(a) | Includes $610 million and $746 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $3 million and $4 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and March 31, 2010, respectively. |
(b) | Includes a $73 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the three months ended June 30, 2010. |
(c) | Includes a $63 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended June 30, 2010. |
(d) | Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010. |
(e) | Includes a $4 million loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Six Months Ended June 30, 2010 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at December 31, | $ | 1,152 | (a) | $ | 551 | |||||
Effective portion of changes in fair value | 334 | (b) | 205 | (e) | ||||||
Reclassifications from accumulated OCI to | Operating Revenue | (328 | )(c) | (231 | ) | |||||
Accumulated OCI derivative gain at June 30, | $ | 1,158 | (a)(d) | $ | 525 | |||||
(a) | Includes $610 million and $585 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2010 and December 31, 2009, respectively, and $3 million and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and December 31, 2009, respectively. |
(b) | Includes a $122 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the block contracts with PECO for the six months ended June 30, 2010. |
(c) | Includes a $97 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the six months ended June 30, 2010. |
(d) | Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010. |
(e) | Includes a $4 million loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd. |
During the three and six months ended June 30, 2011, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $237 million and a $454 million pre-tax gain, respectively, and a $349 million and $543 million pre-tax gain for the three and six months ended June 30, 2010, respectively. Given that the cash flow hedges primarily consist of forward power sales and power swaps and do not include gas options or sales, the ineffectiveness of Generation’s cash flow hedges is primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. This price difference is actively managed through other instruments, which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were increases of $6 million and $1 million for the three months ended June 30, 2011 and 2010, respectively, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. During the six months ended June 30, 2011, cash flow hedge ineffectiveness changed by $8 million, primarily due to changes in market prices during the period, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. Changes in cash flow hedge ineffectiveness for the six months ended June 30, 2010 was not significant. At June 30, 2011 and 2010, cash flow hedge ineffectiveness resulted in an adjustment of $9 million and $1 million, respectively, related to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.
Exelon’s energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $127 million and $231 million pre-tax gain for the three and six months ended June 30, 2011, respectively, and a $245 million and $383 million pre-tax gain for the three and six months ended June 30, 2010, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were increases of $6 million and $1 million pre-tax for the three months ended June 30, 2011 and 2010, respectively. The change in cash flow hedge ineffectiveness for the six months ended
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
June 30, 2011 was an increase of $8 million, and for June 30, 2010 was not significant. At June 30, 2011 and 2010, cash flow hedge ineffectiveness resulted in an adjustment of $9 million and $1 million, respectively, related to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.
Other Derivatives (Exelon and Generation). Other derivative contracts are those that do not qualify or are not designated for hedge accounting. These instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and forward sales. For the three months ended June 30, 2011 and 2010, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
Exelon and Generation | ||||||||||||
Three Months Ended June 30, 2011 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | (21 | ) | $ | 17 | $ | (4 | ) | ||||
Reclassification to realized at settlement | (79 | ) | (47 | ) | (126 | ) | ||||||
Net mark-to-market (losses) | $ | (100 | ) | $ | (30 | ) | $ | (130 | ) | |||
Exelon and Generation | ||||||||||||
Six Months Ended June 30, 2011 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | (20 | ) | $ | 13 | $ | (7 | ) | ||||
Reclassification to realized at settlement | (177 | ) | (96 | ) | (273 | ) | ||||||
Net mark-to-market (losses) | $ | (197 | ) | $ | (83 | ) | $ | (280 | ) | |||
Exelon and Generation | ||||||||||||
Three Months Ended June 30, 2010 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | (72 | ) | $ | 25 | $ | (47 | ) | ||||
Reclassification to realized at settlement | (77 | ) | 1 | (76 | ) | |||||||
Net mark-to-market gains (losses) | $ | (149 | ) | $ | 26 | $ | (123 | ) | ||||
Exelon and Generation | ||||||||||||
Six Months Ended June 30, 2010 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | 181 | $ | 73 | $ | 254 | ||||||
Reclassification to realized at settlement | (146 | ) | 1 | (145 | ) | |||||||
Net mark-to-market gains | $ | 35 | $ | 74 | $ | 109 | ||||||
Proprietary Trading Activities (Exelon and Generation). For the three and six months ended June 30, 2011 and 2010, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on derivative instruments entered into for proprietary trading purposes. Gains and losses associated with proprietary trading are reported as operating revenue in Exelon’s and Generation’s
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
Location on Income Statement | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||
Change in fair value | Operating Revenue | $ | 16 | $ | 19 | $ | 19 | $ | 26 | |||||||||||
Reclassification to realized at settlement | Operating Revenue | (7 | ) | (6 | ) | (12 | ) | (12 | ) | |||||||||||
Net mark-to-market gains | Operating Revenue | $ | 9 | $ | 13 | $ | 7 | $ | 14 | |||||||||||
Credit Risk (Exelon, Generation, ComEd and PECO)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase and normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2011. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs, NYMEX and ICE commodity exchanges, further discussed in Item 3 — Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $43 million and $43 million, respectively.
Rating as of June 30, 2011 | Total Exposure Before Credit Collateral | Credit Collateral | Net Exposure | Number of Counterparties Greater than 10% of Net Exposure | Net Exposure of Counterparties Greater than 10% of Net Exposure | |||||||||||||||
Investment grade | $ | 1,058 | $ | 280 | $ | 778 | 2 | $ | 190 | |||||||||||
Non-investment grade | 13 | 5 | 8 | — | — | |||||||||||||||
No external ratings | ||||||||||||||||||||
Internally rated — investment grade | 37 | 7 | 30 | — | — | |||||||||||||||
Internally rated — non-investment grade | 4 | 2 | 2 | — | — | |||||||||||||||
Total | $ | 1,112 | $ | 294 | $ | 818 | 2 | $ | 190 | |||||||||||
Net Credit Exposure by Type of Counterparty | As of June 30, 2011 | |||
Financial institutions | $ | 320 | ||
Investor-owned utilities, marketers and power producers | 310 | |||
Energy cooperatives and municipalities | 163 | |||
Other | 25 | |||
Total | $ | 818 | ||
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of June 30, 2011, ComEd’s credit exposure to suppliers was immaterial.
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 2 of the 2010 Form 10-K for further information.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of June 30, 2011, PECO’s net credit exposure to suppliers was immaterial and either did not exceed the allowed unsecured credit levels or did not exceed the allowed unsecured credit levels by an amount necessary to trigger a collateral call.
PECO is permitted to recover its costs of procuring electric generation through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further information.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of June 30, 2011, PECO had credit exposure of $13 million under its natural gas supply and asset management agreements.
Collateral and Contingent-Related Features (Exelon, Generation, ComEd, and PECO)
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels and emissions allowances. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Generation also enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearing houses act as the counterparty to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements.
The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on NYMEX and ICE that are fully collateralized) was $614 million and $742 million as of June 30, 2011 and December 31, 2010, respectively. As of June 30, 2011 and December 31, 2010, Generation had the contractual right of offset of $568 million and $717 million, respectively, related to derivative instruments that are assets with the same counterparty under master netting agreements, resulting in a net liability position of $46 million and $25 million, respectively. If Generation had been downgraded to the investment grade rating of BBB- and Baa3, or lost its investment grade credit rating, it would have had additional collateral obligations of approximately $268 million or $1,031 million, respectively, as of June 30, 2011 and approximately $57 million or $944 million, respectively, as of December 31, 2010 related to its financial instruments, including derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements and the application of collateral. See Note 18 of the 2010 Form 10-K for further information regarding the letters of credit supporting the cash collateral.
Generation entered into SFCs with certain utilities, including PECO, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Under the terms of the financial swap contract between Generation and ComEd, if a party is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contract, collateral postings will never exceed $200 million from either ComEd or Generation. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of June 30, 2011, ComEd held both cash and letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts. These amounts were not material. Beginning in June 2010, under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, beginning in December 2010, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of June 30, 2011, ComEd held approximately $20 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 2 of the 2010 Form 10-K for further information.
PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2011, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of June 30, 2011, PECO could have been required to post approximately $40 million of collateral to its counterparties.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
Exelon’s interest rate swaps contain provisions that, in the event of a merger, require that Exelon’s debt maintain an investment grade credit rating from Moody’s or S&P. If Exelon’s debt were to fall below investment grade, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of June 30, 2011, Exelon’s interest rate swap was in an asset position, with a fair value of $14 million.
Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)
As of June 30, 2011 and December 31, 2010, $2 million and $1 million, respectively, of cash collateral received was not offset against net derivative positions, because they were not associated with energy-related derivatives.
Short-Term Borrowings
Exelon meets itsand ComEd meet their short-term liquidity requirements primarily through the issuance of commercial paper,paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool and ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.
On March 23, 2011, Exelon Corporate, Generation and PECO had access toreplaced their unsecured revolving credit facilities with new facilities with aggregate bank commitments of $957$500 million, $4.8$5.3 billion and $574$600 million,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
respectively. Under these facilities, Exelon, Generation and PECO may issue letters of credit in the aggregate amount of up to $200 million, $3.5 billion and $300 million, respectively. OnThe credit facilities expire on March 25, 2010, ComEd replaced its $952 million23, 2016, unless extended in accordance with the terms of the agreements. Each credit facility with a newpermits the applicable borrower to request two one-year extensions. Each credit facility also allows Exelon, Generation and PECO to request increases in the aggregate commitments up to an additional $250 million, in the case of each of Exelon and PECO, and up to an additional $1 billion in the case of Generation. Any such extensions or increases are subject to the approval of the lenders party to the credit facilities in their sole discretion. Exelon Corporate, Generation and PECO incurred $3 million, $37 million and $4 million, respectively, in costs related to the replacement of their credit facilities. These costs included upfront and arranger fees, as well as other costs such as external legal fees and filing costs. These costs will be amortized to interest expense over the terms of the credit facilities.
As of June 30, 2011, ComEd had access to an unsecured revolving credit facility with aggregate bank commitments of $1 billion that extends toexpires on March 25, 2013. 2013, unless extended in accordance with its terms. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $1 billion. ComEd may request two additional one-year extensions. In addition, ComEd may request increases in the aggregate bank commitments under its credit facility up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit facility in their sole discretion.
Borrowings under thateach credit facilityagreement bear interest at a rate that floats dailyselected by the borrower based upon aeither the prime rate or at a fixed rate fixed for a specified interest period based upon a LIBOR-based rate. AddersThe Exelon, Generation and PECO agreements provide for adders of up to 85 basis points for prime-based borrowings and up to 185 basis points for the LIBOR-based borrowings based upon the credit rating of the borrower. At June 30, 2011, Exelon, Generation and PECO adders were 30, 30 and 10 basis points, respectively, for prime based borrowings and 130, 130 and 110 basis points, respectively, for LIBOR-based borrowings. The ComEd agreement provides adders of up to 137.5 basis points for prime-based borrowings and up to 237.5 basis points for LIBOR-based borrowings areto be added, based upon ComEd’s credit rating. As ofAt June 30, 2010, ComEd did not have any2011, ComEd’s adder was 87.5 basis points for prime based borrowings under its credit facility.
and 187.5 basis points for LIBOR-based borrowings.
51
Additionally, on November 4, 2010, Generation entered into a bilateral credit facility, which provides for an aggregate commitment of up to $500 million. The effectiveness and full availability of the credit facility were subject to various conditions. On February 22, 2011, Generation satisfied all conditions to the effectiveness and availability of credit under the credit facility for loans and letters of credit in the aggregate maximum amount of $300 million, which is the limit currently authorized by the board of directors of Exelon Corporation for this credit facility. Availability under the bilateral credit facility extends through December 2015 for $150 million of the $300 million commitment and March 2016 for the remaining $150 million. The bilateral credit facility will be used by Generation primarily to meet requirements for letters of credit but also permits cash borrowings at a rate of LIBOR or a base rate, plus an adder of 200 basis points. No cash borrowings are anticipated under the credit facility. In addition, Generation will pay a facility fee, payable on the first day of each calendar quarter at a rate per annum equal to a specified facility fee rate on the total amount of the credit facility regardless of usage.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon, Generation, ComEd and PECO had the following amounts of commercial paper and credit facility borrowings outstanding at June 30, 20102011 and December 31, 2009:
June 30, | December 31, | |||||||
2010 | 2009 | |||||||
Commercial paper borrowings | ||||||||
Exelon Corporate | $ | — | $ | — | ||||
Generation | — | — | ||||||
ComEd | 289 | — | ||||||
PECO | — | — | ||||||
Credit facility borrowings | ||||||||
ComEd | $ | — | $ | 155 |
Commercial Paper Borrowings | June 30, 2011 | December 31, 2010 | ||||||
Exelon Corporate | $ | 140 | $ | — | ||||
Generation | — | — | ||||||
ComEd | — | — | ||||||
PECO | — | — |
As of June 30, 2011, there were no borrowings under the Registrants’ credit facilities.
Issuance of Long-Term Debt
During the six months ended June 30, 2011, the following long-term debt was issued:
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | |||||||||||
ComEd | First Mortgage Bonds | 1.625 | % | January 15, 2014 | $ | 600 | Used as an interim source of liquidity for the January 2011 contribution to Exelon-sponsored pension plans in which ComEd participates and for other general corporate purposes. |
During the six months ended June 30, 2010, there were no issuances of long-term debt.
Retirement of Long-Term Debt
During the six months ended June 30, 2009,2011, the following long-term debt was issued:
Company | Type | Interest Rate | Maturity | Amount(a) | Use of Proceeds | |||||||||||
Generation | Pollution Control Notes | 5.00 | % | December 1, 2042 | $ | 46 | Used to refinance $46 million of unenhanced tax-exempt variable rate debt that was repurchased on February 23, 2009. | |||||||||
ComEd | First Mortgage Bonds(b) | Variable | March 1, 2020 | 50 | Used to repay credit facility borrowings incurred to repurchase bonds. | |||||||||||
ComEd | First Mortgage Bonds(b) | Variable | March 1, 2017 | 91 | Used to repay credit facility borrowings incurred to repurchase bonds. | |||||||||||
ComEd | First Mortgage Bonds(b) | Variable | March 1, 2021 | 50 | Used to repay credit facility borrowings incurred to repurchase bonds. | |||||||||||
PECO | First Mortgage Bonds | 5.00 | % | October 1, 2014 | 250 | Used to refinance short-term debt and for other general corporate purposes. |
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | $ | 1 | ||||||||
ComEd | Sinking fund debentures | 4.75 | % | December 1, 2011 | 1 |
During the six months ended June 30, 2010, the following long-term debt was retired:
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
ComEd | Sinking fund debentures | 4.75 | % | December 1, 2011 | $ | 1 | ||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | 1 | |||||||||
Generation | Montgomery County Series 1994 B Tax Exempt Bonds | Variable | June 1, 2029 | 13 | ||||||||||
Generation | Indiana County Series 2003 A Tax Exempt Bonds | Variable | June 1, 2027 | 17 | ||||||||||
Generation | York County Series 1993 A Tax Exempt Bonds | Variable | August 1, 2016 | 19 |
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
ComEd | Sinking fund debentures | 4.75 | % | December 1, 2011 | $ | 1 | ||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | 1 | |||||||||
Generation | Montgomery County Series 1994 B Tax Exempt Bonds | Variable | June 1, 2029 | 13 | ||||||||||
Generation | Indiana County Series 2003 A Tax Exempt Bonds | Variable | June 1, 2027 | 17 | ||||||||||
Generation | York County Series 1993 A Tax Exempt Bonds | Variable | August 1, 2016 | 19 | ||||||||||
Generation | Salem County 1993 Series A Tax Exempt Bonds | Variable | March 1, 2025 | 23 | ||||||||||
Generation | Delaware County 1993 Series A Tax Exempt Bonds | Variable | August 1, 2016 | 24 | ||||||||||
Generation | Montgomery County Series 1996 A Tax Exempt Bonds | Variable | March 1, 2034 | 34 | ||||||||||
Generation | Montgomery County Series 1994 A Tax Exempt Bonds | Variable | June 1, 2029 | 83 | ||||||||||
Exelon | 2005 Senior Notes | 4.45 | % | June 15, 2010 | 400 | |||||||||
PECO | PETT Transition Bonds | 6.52 | % | September 1, 2010 | 402 |
52
(Dollars in millions, except per share data, unless otherwise noted)
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
Generation | Salem County 1993 Series A Tax Exempt Bonds | Variable | March 1, 2025 | $ | 23 | |||||||||
Generation | Delaware County Series 1993 A Tax Exempt Bonds | Variable | August 1, 2016 | 24 | ||||||||||
Generation | Montgomery County Series 1996 A Tax Exempt Bonds | Variable | March 1, 2034 | 34 | ||||||||||
Generation | Montgomery County Series 1994 A Tax Exempt Bonds | Variable | June 1, 2029 | 83 | ||||||||||
Exelon | 2005 Senior Notes | 4.45 | % | June 15, 2010 | 400 | |||||||||
PECO | PETT Transition Bonds | 6.52 | % | September 1, 2010 | 402 |
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
Generation | Pollution Control Notes | Variable | December 1, 2042 | $ | 46 | |||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | 1 | |||||||||
ComEd | First Mortgage Bonds (a) | Variable | March 1, 2020 | 50 | ||||||||||
ComEd | First Mortgage Bonds (a) | Variable | March 1, 2017 | 91 | ||||||||||
ComEd | First Mortgage Bonds (a) | Variable | March 1, 2021 | 50 | ||||||||||
ComEd | First Mortgage Bonds | 5.70 | % | January 15, 2009 | 16 | |||||||||
ComEd | Sinking fund debentures | 4.625-4.75 | % | Various | 1 | |||||||||
PECO | PETT Transition Bonds | 7.65 | % | September 1, 2009 | 319 | |||||||||
PECO | PETT Transition Bonds | 6.52 | % | March 1, 2010 | 11 |
Variable Rate Debt
Under the terms of ComEd’s variable-rate tax-exempt debt agreements, ComEd may be required to repurchase any outstandingthat debt before its stated maturity unless supported by sufficient letters of credit. If ComEd was required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. ComEd has classified amounts outstanding under these debt agreements as long-term debt based on management’s intent and ability to renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under its existing long-term credit facilities.
Accounts Receivable AgreementFair Value Hedges
Income Statement Classification | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | ||||||||||||||
Six Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Interest expense | $ | — | $ | 5 | $ | — | $ | (5 | ) |
53
(Dollars in millions, except per share data, unless otherwise noted)
At June 30, 2011 and December 31, 2010, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $14 million and $14 million, respectively, which expire in 2015. During the three and six months ended June 30, 2011 and 2010, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.
6. Derivative Financial InstrumentsFair Value Measurement (Exelon, Generation, ComEd and PECO)
Fair value accounting guidance requires the fair value of derivative instruments to certain risks relatedbe shown in the Notes to ongoing business operations. The primary risks managed by usingthe Consolidated Financial Statements on a gross basis, even when the derivative instruments are commodity price risksubject to master netting agreements and interest rate risk. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuationsqualify for net presentation in the pricesConsolidated Balance Sheet. In the table below, Generation’s cash flow hedges, other derivatives and proprietary trading derivatives are shown gross and the impact of electricity, fossil fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associatedthe netting of fair value balances with market fluctuations by entering into physical contractsthe same counterparty, as well as financial derivative contracts including swaps, futures, forwards, optionsnetting of collateral, is aggregated in the collateral and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, whichnetting column. Excluded from the tables below are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt, commercial paper and lines of credit.
The following table provides a summary of the derivative contracts forfair value balances recorded by the forward saleRegistrants as of generation, power procurement agreements,June 30, 2011:
Generation | ComEd | PECO | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Derivatives | Cash Flow Hedges (a)(d) | Other Derivatives | Proprietary Trading | Collateral and Netting (b) | Subtotal (c) | Other Derivatives (a)(e) | Other Derivatives (d) | Other Derivatives | Intercompany Eliminations (a)(d) | Total Derivatives | ||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 335 | $ | 841 | $ | 173 | $ | (911 | ) | $ | 438 | $ | — | $ | — | $ | — | $ | — | $ | 438 | |||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 414 | — | — | — | 414 | — | — | — | (414 | ) | — | |||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 148 | 399 | 60 | (297 | ) | 310 | — | — | 14 | — | 324 | |||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 345 | — | — | — | 345 | — | — | — | (345 | ) | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,242 | $ | 1,240 | $ | 233 | $ | (1,208 | ) | $ | 1,507 | $ | — | $ | — | $ | 14 | $ | (759 | ) | $ | 762 | ||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (46 | ) | $ | (452 | ) | $ | (150 | ) | $ | 601 | $ | (47 | ) | $ | (1 | ) | $ | (2 | ) | $ | — | $ | — | $ | (50 | ) | |||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (412 | ) | (2 | ) | — | 414 | — | ||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (50 | ) | (119 | ) | (49 | ) | 182 | (36 | ) | (30 | ) | — | — | — | (66 | ) | ||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (345 | ) | — | — | 345 | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (96 | ) | (571 | ) | (199 | ) | 783 | (83 | ) | (788 | ) | (4 | ) | — | 759 | (116 | ) | |||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 1,146 | $ | 669 | $ | 34 | $ | (425 | ) | $ | 1,424 | $ | (788 | ) | $ | (4 | ) | $ | 14 | $ | — | $ | 646 | |||||||||||||||||
(a) | Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $412 million and $345 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. |
(b) | Represents the netting of fair value balances with the same counterparty and the application of collateral. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(c) | Current and noncurrent assets are shown net of collateral of $300 million and $92 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $9 million and $24 million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $425 million at June 30, 2011. |
(d) | Includes current assets for Generation and current liabilities for PECO of $2 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of June 30, 2011. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in fair value of PECO’s block contracts were recorded and the mark-to-market balances previously recorded are being amortized over the terms of the contracts. |
(e) | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2010:
Generation | ComEd | PECO | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Derivatives | Cash Flow Hedges (a)(d) | Other Derivatives | Proprietary Trading | Collateral and Netting (b) | Subtotal (c) | Other Derivatives (a)(e) | Other Derivatives (d) | Other Derivatives | Intercompany Eliminations (a)(d) | Total Derivatives | ||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 532 | $ | 1,203 | $ | 225 | $ | (1,473 | ) | $ | 487 | $ | — | $ | — | $ | — | $ | — | $ | 487 | |||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 455 | — | — | — | 455 | — | — | — | (455 | ) | — | |||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 204 | 547 | 56 | (416 | ) | 391 | 4 | — | 14 | — | 409 | |||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 525 | — | — | — | 525 | — | — | — | (525 | ) | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,716 | $ | 1,750 | $ | 281 | $ | (1,889 | ) | $ | 1,858 | $ | 4 | $ | — | $ | 14 | $ | (980 | ) | $ | 896 | ||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (21 | ) | $ | (551 | ) | $ | (200 | ) | $ | 738 | $ | (34 | ) | $ | — | $ | (4 | ) | $ | — | $ | — | $ | (38 | ) | ||||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (450 | ) | (5 | ) | — | 455 | — | ||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (24 | ) | (143 | ) | (54 | ) | 200 | (21 | ) | — | — | — | — | (21 | ) | |||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (525 | ) | — | — | 525 | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (45 | ) | (694 | ) | (254 | ) | 938 | (55 | ) | (975 | ) | (9 | ) | — | 980 | (59 | ) | |||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 1,671 | $ | 1,056 | $ | 27 | $ | (951 | ) | $ | 1,803 | $ | (971 | ) | $ | (9 | ) | $ | 14 | $ | — | $ | 837 | |||||||||||||||||
(a) | Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $450 million and $525 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. |
(b) | Represents the netting of fair value balances with the same counterparty and the application of collateral. |
(c) | Current and noncurrent assets are shown net of collateral of $725 million and $199 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $10 million and $17 million, respectively. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $951 million at December 31, 2010. |
(d) | Includes current assets for Generation and current liabilities for PECO of $5 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of December 31, 2010. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in the fair value of PECO’s block contracts were recorded. Previously recorded mark-to-market-balances are being amortized over the term of the contract. |
(e) | Includes noncurrent assets relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Cash Flow Hedges (Exelon, Generation and natural gas supply agreements. For economicComEd). Economic hedges that qualify and are designated as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At June 30, 2011, Generation had net unrealized pre-tax gains on effective cash flow hedges of $ 1,135 million being deferred within accumulated OCI, including $757 million related to the portionfinancial swap with ComEd. Amounts recorded in accumulated OCI related to changes in energy commodity cash flow hedges are reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs. Reclassifications from OCI are included in operating revenues, purchased power and fuel in Exelon’s and Generation’s Consolidated Statements of Operations, depending on the commodities involved in the hedged transaction. Based on market prices at June 30, 2011, approximately $699 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation, including approximately $412 million related to the financial swap with ComEd. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices. Generation expects the settlement of the majority of its cash flow hedges, including the ComEd financial swap contract, will occur during 2011 through 2013.
Exelon discontinues hedge accounting prospectively when it determines that the derivative gain or loss that is no longer effective in offsetting changes in the changecash flows of a hedged item, in valuethe case of forward-starting hedges, or when it is no longer probable that the underlying exposure is deferred in accumulated OCIforecasted transaction will occur. For the three months ended June 30, 2011 and later2010, amounts reclassified into earnings whenas a result of the underlying transaction occurs. For economic hedges that do not qualify or are not designated asdiscontinuance of cash flow hedges were immaterial.
The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and six months ended June 30, 2011 and 2010, containing information about the changes in the fair value of cash flow hedges and the derivative are recognized in earnings each period and are classified as other derivativesreclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the following tables. Non-derivativeultimate recognition of net revenues at the contracted price.
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Three Months Ended June 30, 2011 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at March 31, | $ | 941 | (a) | $ | 354 | |||||
Effective portion of changes in fair value | (106 | )(b) | (64 | ) | ||||||
Reclassifications from accumulated OCI to | Operating Revenue | (143 | )(c) | (77 | ) | |||||
Ineffective portion recognized in income | Purchased Power | (4 | ) | (4 | ) | |||||
Accumulated OCI derivative gain at June 30, | $ | 688 | (a)(d) | $ | 209 | |||||
(a) | Includes $458 million and $562 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $2 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and March 31, 2011, respectively. |
(b) | Includes $39 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract. |
(c) | Includes a $65 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the three months ended June 30, 2011. |
(d) | Excludes $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Six Months Ended June 30, 2011 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at December 31, 2010 | $ | 1,011 | (a) | $ | 400 | |||||
Effective portion of changes in fair value | (43 | )(b) | (46 | ) | ||||||
Reclassifications from accumulated OCI to | Operating Revenue | (275 | )(c) | (140 | ) | |||||
Ineffective portion recognized in income | Purchased Power | (5 | ) | (5 | ) | |||||
Accumulated OCI derivative gain at June 30, | $ | 688 | (a)(d) | $ | 209 | |||||
(a) | Includes $458 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and December 31, 2010. |
(b) | Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the six months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract. |
(c) | Includes a $133 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd and a $2 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the six months ended June 30, 2011. |
(d) | Excludes $2 million of gains, net of taxes, related to interest rate swaps. |
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Three Months Ended June 30, 2010 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at March 31, 2010 | $ | 1,703 | (a) | $ | 934 | |||||
Effective portion of changes in fair value | (335 | )(b) | (262 | ) | ||||||
Reclassifications from accumulated OCI to net income | Operating Revenue | (211 | )(c) | (148 | ) | |||||
Ineffective portion recognized in income | Purchased Power | 1 | 1 | (e) | ||||||
Accumulated OCI derivative gain at June 30, 2010 | $ | 1,158 | (a)(d) | $ | 525 | |||||
(a) | Includes $610 million and $746 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $3 million and $4 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and March 31, 2010, respectively. |
(b) | Includes a $73 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the three months ended June 30, 2010. |
(c) | Includes a $63 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended June 30, 2010. |
(d) | Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010. |
(e) | Includes a $4 million loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Six Months Ended June 30, 2010 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at December 31, | $ | 1,152 | (a) | $ | 551 | |||||
Effective portion of changes in fair value | 334 | (b) | 205 | (e) | ||||||
Reclassifications from accumulated OCI to | Operating Revenue | (328 | )(c) | (231 | ) | |||||
Accumulated OCI derivative gain at June 30, | $ | 1,158 | (a)(d) | $ | 525 | |||||
(a) | Includes $610 million and $585 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2010 and December 31, 2009, respectively, and $3 million and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and December 31, 2009, respectively. |
(b) | Includes a $122 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the block contracts with PECO for the six months ended June 30, 2010. |
(c) | Includes a $97 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the six months ended June 30, 2010. |
(d) | Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010. |
(e) | Includes a $4 million loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd. |
During the three and six months ended June 30, 2011, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $237 million and a $454 million pre-tax gain, respectively, and a $349 million and $543 million pre-tax gain for access to additional generationthe three and forsix months ended June 30, 2010, respectively. Given that the cash flow hedges primarily consist of forward power sales to load-serving entities are accounted for primarily underand power swaps and do not include gas options or sales, the accrual method of accounting, which is further discussed in Note 18 of the 2009 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portionineffectiveness of Generation’s overall energy marketing activities.
Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were increases of $6 million and $1 million for the three months ended June 30, 2011 and 2010, respectively, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. During the six months ended June 30, 2011, cash flow hedge ineffectiveness changed by $8 million, primarily due to changes in market prices during the period, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. Changes in cash flow hedge ineffectiveness for the six months ended June 30, 2010 was not significant. At June 30, 2011 and 2010, cash flow hedge ineffectiveness resulted in an adjustment of $9 million and $1 million, respectively, related to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.
54
(Dollars in millions, except per share data, unless otherwise noted)
June 30, 2011 was an increase of $8 million, and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over three-year periods. As offor June 30, 2010 the percentage of expected generation hedged was 96%-99%, 86%-89%, and 57%-60% for the remainder of 2010,not significant. At June 30, 2011 and 2012, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include2010, cash flow hedges, other derivativeshedge ineffectiveness resulted in an adjustment of $9 million and certain non-derivative contracts including sales$1 million, respectively, related to ComEd and PECO to serve their retail load.
Other Derivatives (Exelon and ICC-approved procurement methodologies permitting ComEdGeneration). Other derivative contracts are those that do not qualify or are not designated for hedge accounting. These instruments represent economic hedges that mitigate exposure to recover its electricity procurement costs from retail customers with no mark-up, ComEd’s price riskfluctuations in commodity prices and include financial options, futures, swaps, and forward sales. For the three months ended June 30, 2011 and 2010, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to power procurement is limited.
Exelon and Generation | ||||||||||||
Three Months Ended June 30, 2011 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | (21 | ) | $ | 17 | $ | (4 | ) | ||||
Reclassification to realized at settlement | (79 | ) | (47 | ) | (126 | ) | ||||||
Net mark-to-market (losses) | $ | (100 | ) | $ | (30 | ) | $ | (130 | ) | |||
Exelon and Generation | ||||||||||||
Six Months Ended June 30, 2011 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | (20 | ) | $ | 13 | $ | (7 | ) | ||||
Reclassification to realized at settlement | (177 | ) | (96 | ) | (273 | ) | ||||||
Net mark-to-market (losses) | $ | (197 | ) | $ | (83 | ) | $ | (280 | ) | |||
Exelon and Generation | ||||||||||||
Three Months Ended June 30, 2010 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | (72 | ) | $ | 25 | $ | (47 | ) | ||||
Reclassification to realized at settlement | (77 | ) | 1 | (76 | ) | |||||||
Net mark-to-market gains (losses) | $ | (149 | ) | $ | 26 | $ | (123 | ) | ||||
Exelon and Generation | ||||||||||||
Six Months Ended June 30, 2010 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | 181 | $ | 73 | $ | 254 | ||||||
Reclassification to realized at settlement | (146 | ) | 1 | (145 | ) | |||||||
Net mark-to-market gains | $ | 35 | $ | 74 | $ | 109 | ||||||
Proprietary Trading Activities (Exelon and Generation). For the three and six months ended June 30, 2011 and 2010, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and ComEd are eliminated.
Generation’s
55
(Dollars in millions, except per share data, unless otherwise noted)
Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
Location on Income Statement | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||
Change in fair value | Operating Revenue | $ | 16 | $ | 19 | $ | 19 | $ | 26 | |||||||||||
Reclassification to realized at settlement | Operating Revenue | (7 | ) | (6 | ) | (12 | ) | (12 | ) | |||||||||||
Net mark-to-market gains | Operating Revenue | $ | 9 | $ | 13 | $ | 7 | $ | 14 | |||||||||||
Credit Risk (Exelon, Generation, ComEd and PECO)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase and normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2011. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs, NYMEX and ICE commodity exchanges, further discussed in Item 3 — Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $43 million and $43 million, respectively.
Rating as of June 30, 2011 | Total Exposure Before Credit Collateral | Credit Collateral | Net Exposure | Number of Counterparties Greater than 10% of Net Exposure | Net Exposure of Counterparties Greater than 10% of Net Exposure | |||||||||||||||
Investment grade | $ | 1,058 | $ | 280 | $ | 778 | 2 | $ | 190 | |||||||||||
Non-investment grade | 13 | 5 | 8 | — | — | |||||||||||||||
No external ratings | ||||||||||||||||||||
Internally rated — investment grade | 37 | 7 | 30 | — | — | |||||||||||||||
Internally rated — non-investment grade | 4 | 2 | 2 | — | — | |||||||||||||||
Total | $ | 1,112 | $ | 294 | $ | 818 | 2 | $ | 190 | |||||||||||
Net Credit Exposure by Type of Counterparty | As of June 30, 2011 | |||
Financial institutions | $ | 320 | ||
Investor-owned utilities, marketers and power producers | 310 | |||
Energy cooperatives and municipalities | 163 | |||
Other | 25 | |||
Total | $ | 818 | ||
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of June 30, 2011, ComEd’s credit exposure to suppliers was immaterial.
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 2 of the 2010 Form 10-K for further information.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of June 30, 2011, PECO’s net credit exposure to suppliers was immaterial and either did not exceed the allowed unsecured credit levels or did not exceed the allowed unsecured credit levels by an amount necessary to trigger a collateral call.
PECO is permitted to recover its costs of procuring electric generation through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further information.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of June 30, 2011, PECO had credit exposure of $13 million under its natural gas supply and asset management agreements.
Proprietary Trading.Collateral and Contingent-Related Features (Exelon, Generation, ComEd, and PECO)
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels and emissions allowances. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Generation also enters into certain energy-relatedcommodity transactions on NYMEX and ICE. The NYMEX and ICE clearing houses act as the counterparty to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements.
The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on NYMEX and ICE that are fully collateralized) was $614 million and $742 million as of June 30, 2011 and December 31, 2010, respectively. As of June 30, 2011 and December 31, 2010, Generation had the contractual right of offset of $568 million and $717 million, respectively, related to derivative instruments that are assets with the same counterparty under master netting agreements, resulting in a net liability position of $46 million and $25 million, respectively. If Generation had been downgraded to the investment grade rating of BBB- and Baa3, or lost its investment grade credit rating, it would have had additional collateral obligations of approximately $268 million or $1,031 million, respectively, as of June 30, 2011 and approximately $57 million or $944 million, respectively, as of December 31, 2010 related to its financial instruments, including derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements and the application of collateral. See Note 18 of the 2010 Form 10-K for proprietary trading purposes. Proprietary trading includes all contractsfurther information regarding the letters of credit supporting the cash collateral.
Generation entered into purelySFCs with certain utilities, including PECO, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to profitpost collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Under the terms of the financial swap contract between Generation and ComEd, if a party is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contract, collateral postings will never exceed $200 million from either ComEd or Generation. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market price changesprices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of June 30, 2011, ComEd held both cash and letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts. These amounts were not material. Beginning in June 2010, under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, beginning in December 2010, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of June 30, 2011, ComEd held approximately $20 million in the form of cash and letters of credit as opposedmargin for both the annual and long-term REC obligations. See Note 2 of the 2010 Form 10-K for further information.
PECO’s natural gas procurement contracts contain provisions that could require PECO to hedgingpost collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2011, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of June 30, 2011, PECO could have been required to post approximately $40 million of collateral to its counterparties.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
Exelon’s interest rate swaps contain provisions that, in the event of a merger, require that Exelon’s debt maintain an exposureinvestment grade credit rating from Moody’s or S&P. If Exelon’s debt were to fall below investment grade, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of June 30, 2011, Exelon’s interest rate swap was in an asset position, with a fair value of $14 million.
Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and isGeneration)
As of June 30, 2011 and December 31, 2010, $2 million and $1 million, respectively, of cash collateral received was not offset against net derivative positions, because they were not associated with energy-related derivatives.
7. Debt and Credit Agreements (Exelon, Generation, ComEd and PECO)
Short-Term Borrowings
Exelon and ComEd meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool.
On March 23, 2011, Exelon Corporate, Generation and PECO replaced their unsecured revolving credit facilities with new facilities with aggregate bank commitments of $500 million, $5.3 billion and $600 million,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
respectively. Under these facilities, Exelon, Generation and PECO may issue letters of credit in the aggregate amount of up to $200 million, $3.5 billion and $300 million, respectively. The credit facilities expire on March 23, 2016, unless extended in accordance with the terms of the agreements. Each credit facility permits the applicable borrower to request two one-year extensions. Each credit facility also allows Exelon, Generation and PECO to request increases in the aggregate commitments up to an additional $250 million, in the case of each of Exelon and PECO, and up to an additional $1 billion in the case of Generation. Any such extensions or increases are subject to limits establishedthe approval of the lenders party to the credit facilities in their sole discretion. Exelon Corporate, Generation and PECO incurred $3 million, $37 million and $4 million, respectively, in costs related to the replacement of their credit facilities. These costs included upfront and arranger fees, as well as other costs such as external legal fees and filing costs. These costs will be amortized to interest expense over the terms of the credit facilities.
As of June 30, 2011, ComEd had access to an unsecured revolving credit facility with aggregate bank commitments of $1 billion that expires on March 25, 2013, unless extended in accordance with its terms. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $1 billion. ComEd may request two additional one-year extensions. In addition, ComEd may request increases in the aggregate bank commitments under its credit facility up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit facility in their sole discretion.
Borrowings under each credit agreement bear interest at a rate selected by Exelon’s RMC.the borrower based upon either the prime rate or at a fixed rate for a specified period based upon a LIBOR-based rate. The proprietary trading activities, which included volumesExelon, Generation and PECO agreements provide for adders of 889 GWhsup to 85 basis points for prime-based borrowings and 1,808 GWhsup to 185 basis points for the threeLIBOR-based borrowings based upon the credit rating of the borrower. At June 30, 2011, Exelon, Generation and PECO adders were 30, 30 and 10 basis points, respectively, for prime based borrowings and 130, 130 and 110 basis points, respectively, for LIBOR-based borrowings. The ComEd agreement provides adders of up to 137.5 basis points for prime-based borrowings and up to 237.5 basis points for LIBOR-based borrowings to be added, based upon ComEd’s credit rating. At June 30, 2011, ComEd’s adder was 87.5 basis points for prime based borrowings and 187.5 basis points for LIBOR-based borrowings.
Generation, ComEd and PECO had $30 million, $32 million and $32 million, respectively, of additional credit facility agreements with minority and community banks located primarily within ComEd’s and PECO’s service territories. These facilities expire on October 21, 2011 and are solely utilized to issue letters of credit. As of June 30, 2011, letters of credit issued under these agreements totaled $25 million, $21 million and $20 million for Generation, ComEd and PECO, respectively.
Additionally, on November 4, 2010, Generation entered into a bilateral credit facility, which provides for an aggregate commitment of up to $500 million. The effectiveness and full availability of the credit facility were subject to various conditions. On February 22, 2011, Generation satisfied all conditions to the effectiveness and availability of credit under the credit facility for loans and letters of credit in the aggregate maximum amount of $300 million, which is the limit currently authorized by the board of directors of Exelon Corporation for this credit facility. Availability under the bilateral credit facility extends through December 2015 for $150 million of the $300 million commitment and March 2016 for the remaining $150 million. The bilateral credit facility will be used by Generation primarily to meet requirements for letters of credit but also permits cash borrowings at a rate of LIBOR or a base rate, plus an adder of 200 basis points. No cash borrowings are anticipated under the credit facility. In addition, Generation will pay a facility fee, payable on the first day of each calendar quarter at a rate per annum equal to a specified facility fee rate on the total amount of the credit facility regardless of usage.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon, Generation, ComEd and PECO had the following amounts of commercial paper borrowings outstanding at June 30, 2011 and December 31, 2010:
Commercial Paper Borrowings | June 30, 2011 | December 31, 2010 | ||||||
Exelon Corporate | $ | 140 | $ | — | ||||
Generation | — | — | ||||||
ComEd | — | — | ||||||
PECO | — | — |
As of June 30, 2011, there were no borrowings under the Registrants’ credit facilities.
Issuance of Long-Term Debt
During the six months ended June 30, 2011, the following long-term debt was issued:
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | |||||||||||
ComEd | First Mortgage Bonds | 1.625 | % | January 15, 2014 | $ | 600 | Used as an interim source of liquidity for the January 2011 contribution to Exelon-sponsored pension plans in which ComEd participates and for other general corporate purposes. |
During the six months ended June 30, 2010, and 2,003 GWhs and 4,334 GWhs forthere were no issuances of long-term debt.
Retirement of Long-Term Debt
During the three and six months ended June 30, 2009, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. Neither ComEd nor PECO enter into derivatives for proprietary trading purposes.
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | $ | 1 | ||||||||
ComEd | Sinking fund debentures | 4.75 | % | December 1, 2011 | 1 |
During the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to achieve a lower cost of capital. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in each of Exelon, Generation, and ComEd’s pre-tax income for the three and six months ended June 30, 2010.
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
ComEd | Sinking fund debentures | 4.75 | % | December 1, 2011 | $ | 1 | ||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | 1 | |||||||||
Generation | Montgomery County Series 1994 B Tax Exempt Bonds | Variable | June 1, 2029 | 13 | ||||||||||
Generation | Indiana County Series 2003 A Tax Exempt Bonds | Variable | June 1, 2027 | 17 | ||||||||||
Generation | York County Series 1993 A Tax Exempt Bonds | Variable | August 1, 2016 | 19 | ||||||||||
Generation | Salem County 1993 Series A Tax Exempt Bonds | Variable | March 1, 2025 | 23 | ||||||||||
Generation | Delaware County 1993 Series A Tax Exempt Bonds | Variable | August 1, 2016 | 24 | ||||||||||
Generation | Montgomery County Series 1996 A Tax Exempt Bonds | Variable | March 1, 2034 | 34 | ||||||||||
Generation | Montgomery County Series 1994 A Tax Exempt Bonds | Variable | June 1, 2029 | 83 | ||||||||||
Exelon | 2005 Senior Notes | 4.45 | % | June 15, 2010 | 400 | |||||||||
PECO | PETT Transition Bonds | 6.52 | % | September 1, 2010 | 402 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Variable Rate Debt
Under the terms of ComEd’s variable-rate tax-exempt debt agreements, ComEd may be required to repurchase that debt before its stated maturity unless supported by sufficient letters of credit. If ComEd was required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. ComEd has classified amounts outstanding under these debt agreements as long-term debt based on management’s intent and ability to renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under its existing long-term credit facility.
Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:
Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||
Six Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
Income Statement Classification | 2010 | 2009 | 2010 | 2009 | ||||||||||||
Interest expense | $ | 5 | $ | (6 | ) | $ | (5 | ) | $ | 6 |
Income Statement Classification | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | ||||||||||||||
Six Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Interest expense | $ | — | $ | 5 | $ | — | $ | (5 | ) |
56
(Dollars in millions, except per share data, unless otherwise noted)
At June 30, 20102011 and December 31, 2009,2010, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $15$14 million and $10$14 million, respectively.respectively, which expire in 2015. During the three and six months ended June 30, 20102011 and 2009,2010, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.
Fair Value Measurement (Exelon, Generation, ComEd and PECO)
Fair value accounting guidance requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. In the table below, Generation’s cash flow hedges, other derivatives and proprietary trading derivatives are shown gross and the impact of the netting of fair value balances with the same counterparty, as well as netting of collateral, is aggregated in the collateral and netting column. Excluded from the tables below are economic hedges that qualify for the normal purchases and normal sales scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.
57
Generation | ComEd | PECO | Other | Exelon | ||||||||||||||||||||||||||||||||||||||||||||
Collateral | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash Flow | Other | Proprietary | and | IL Settlement | Cash Flow | Other | Other | Intercompany | Total | |||||||||||||||||||||||||||||||||||||||
Derivatives | Hedges(a,d) | Derivatives | Trading | Netting(b) | Subtotal(c) | Swap(a) | Hedges(e) | Subtotal | Derivatives (d) | Derivatives | Eliminations(a) | Derivatives | ||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 581 | $ | 1,085 | $ | 194 | $ | (1,442 | ) | $ | 418 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 418 | |||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 386 | — | — | — | 386 | — | — | — | — | — | (386 | ) | — | |||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 396 | 827 | 140 | (751 | ) | 612 | — | — | — | — | 15 | — | 627 | |||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 629 | — | — | — | 629 | — | — | — | — | — | (629 | ) | — | |||||||||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,992 | $ | 1,912 | $ | 334 | $ | (2,193 | ) | $ | 2,045 | $ | — | $ | — | $ | — | $ | — | $ | 15 | $ | (1,015 | ) | $ | 1,045 | ||||||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (26 | ) | $ | (691 | ) | $ | (181 | ) | $ | 852 | $ | (46 | ) | $ | — | $ | (6 | ) | $ | (6 | ) | $ | (2 | ) | $ | — | $ | — | $ | (54 | ) | ||||||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (383 | ) | — | (383 | ) | (3 | ) | — | 386 | — | |||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (50 | ) | (285 | ) | (114 | ) | 443 | (6 | ) | — | — | — | (2 | ) | — | — | (8 | ) | ||||||||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (627 | ) | — | (627 | ) | (2 | ) | — | 629 | — | |||||||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (76 | ) | (976 | ) | (295 | ) | 1,295 | (52 | ) | (1,010 | ) | (6 | ) | (1,016 | ) | (9 | ) | — | 1,015 | (62 | ) | |||||||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 1,916 | $ | 936 | $ | 39 | $ | (898 | ) | $ | 1,993 | $ | (1,010 | ) | $ | (6 | ) | $ | (1,016 | ) | $ | (9 | ) | $ | 15 | $ | — | $ | 983 | |||||||||||||||||||
Generation | ComEd | PECO | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Derivatives | Cash Flow Hedges (a)(d) | Other Derivatives | Proprietary Trading | Collateral and Netting (b) | Subtotal (c) | Other Derivatives (a)(e) | Other Derivatives (d) | Other Derivatives | Intercompany Eliminations (a)(d) | Total Derivatives | ||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 335 | $ | 841 | $ | 173 | $ | (911 | ) | $ | 438 | $ | — | $ | — | $ | — | $ | — | $ | 438 | |||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 414 | — | — | — | 414 | — | — | — | (414 | ) | — | |||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 148 | 399 | 60 | (297 | ) | 310 | — | — | 14 | — | 324 | |||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 345 | — | — | — | 345 | — | — | — | (345 | ) | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,242 | $ | 1,240 | $ | 233 | $ | (1,208 | ) | $ | 1,507 | $ | — | $ | — | $ | 14 | $ | (759 | ) | $ | 762 | ||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (46 | ) | $ | (452 | ) | $ | (150 | ) | $ | 601 | $ | (47 | ) | $ | (1 | ) | $ | (2 | ) | $ | — | $ | — | $ | (50 | ) | |||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (412 | ) | (2 | ) | — | 414 | — | ||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (50 | ) | (119 | ) | (49 | ) | 182 | (36 | ) | (30 | ) | — | — | — | (66 | ) | ||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (345 | ) | — | — | 345 | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (96 | ) | (571 | ) | (199 | ) | 783 | (83 | ) | (788 | ) | (4 | ) | — | 759 | (116 | ) | |||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 1,146 | $ | 669 | $ | 34 | $ | (425 | ) | $ | 1,424 | $ | (788 | ) | $ | (4 | ) | $ | 14 | $ | — | $ | 646 | |||||||||||||||||
(a) | Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of |
(b) | Represents the netting of fair value balances with the same counterparty and the application of collateral. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(c) | Current and noncurrent assets are shown net of collateral of |
58
Generation | ComEd | PECO | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Collateral | ||||||||||||||||||||||||||||||||||||||||
Cash Flow | Other | Proprietary | and | IL Settlement | Other | Other | Intercompany | Total | ||||||||||||||||||||||||||||||||
Derivatives | Hedges(a) | Derivatives | Trading | Netting(b) | Subtotal(c) | Swap(a) | Derivatives (d) | Derivatives | Eliminations(a) | Derivatives | ||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 576 | $ | 913 | $ | 193 | $ | (1,306 | ) | $ | 376 | $ | — | $ | — | $ | — | $ | — | $ | 376 | |||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 302 | — | — | — | 302 | — | — | — | (302 | ) | — | |||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 423 | 792 | 102 | (678 | ) | 639 | — | — | 10 | — | 649 | |||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 671 | — | — | — | 671 | — | — | — | (671 | ) | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,972 | $ | 1,705 | $ | 295 | $ | (1,984 | ) | $ | 1,988 | $ | — | $ | — | $ | 10 | $ | (973 | ) | $ | 1,025 | ||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (18 | ) | $ | (743 | ) | $ | (172 | ) | $ | 735 | $ | (198 | ) | $ | — | $ | — | $ | — | $ | — | $ | (198 | ) | |||||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (302 | ) | — | — | 302 | — | |||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (42 | ) | (183 | ) | (98 | ) | 302 | (21 | ) | — | (2 | ) | — | — | (23 | ) | ||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (669 | ) | (2 | ) | — | 671 | — | ||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (60 | ) | (926 | ) | (270 | ) | 1,037 | (219 | ) | (971 | ) | (4 | ) | — | 973 | (221 | ) | |||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 1,912 | $ | 779 | $ | 25 | $ | (947 | ) | $ | 1,769 | $ | (971 | ) | $ | (4 | ) | $ | 10 | $ | — | $ | 804 | |||||||||||||||||
(d) | Includes |
(e) | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2010:
Generation | ComEd | PECO | Other | Exelon | ||||||||||||||||||||||||||||||||||||
Derivatives | Cash Flow Hedges (a)(d) | Other Derivatives | Proprietary Trading | Collateral and Netting (b) | Subtotal (c) | Other Derivatives (a)(e) | Other Derivatives (d) | Other Derivatives | Intercompany Eliminations (a)(d) | Total Derivatives | ||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 532 | $ | 1,203 | $ | 225 | $ | (1,473 | ) | $ | 487 | $ | — | $ | — | $ | — | $ | — | $ | 487 | |||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 455 | — | — | — | 455 | — | — | — | (455 | ) | — | |||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 204 | 547 | 56 | (416 | ) | 391 | 4 | — | 14 | — | 409 | |||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 525 | — | — | — | 525 | — | — | — | (525 | ) | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,716 | $ | 1,750 | $ | 281 | $ | (1,889 | ) | $ | 1,858 | $ | 4 | $ | — | $ | 14 | $ | (980 | ) | $ | 896 | ||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (21 | ) | $ | (551 | ) | $ | (200 | ) | $ | 738 | $ | (34 | ) | $ | — | $ | (4 | ) | $ | — | $ | — | $ | (38 | ) | ||||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (450 | ) | (5 | ) | — | 455 | — | ||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (24 | ) | (143 | ) | (54 | ) | 200 | (21 | ) | — | — | — | — | (21 | ) | |||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (525 | ) | — | — | 525 | — | |||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (45 | ) | (694 | ) | (254 | ) | 938 | (55 | ) | (975 | ) | (9 | ) | — | 980 | (59 | ) | |||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 1,671 | $ | 1,056 | $ | 27 | $ | (951 | ) | $ | 1,803 | $ | (971 | ) | $ | (9 | ) | $ | 14 | $ | — | $ | 837 | |||||||||||||||||
(a) | Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $450 million and $525 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. |
(b) | Represents the netting of fair value balances with the same counterparty and the application of collateral. |
(c) | Current and noncurrent assets are shown net of collateral of $725 million and $199 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $10 million and $17 million, respectively. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $951 million at December 31, |
(d) | Includes current assets for Generation and current liabilities for PECO of $5 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of December 31, 2010. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in the fair value of PECO’s block contracts were recorded. Previously recorded mark-to-market-balances are being amortized over the term of the contract. |
(e) | Includes noncurrent assets relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
59
(Dollars in millions, except per share data, unless otherwise noted)
Cash Flow Hedges (Exelon, Generation and ComEd).Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At June 30, 2010,2011, Generation had net unrealized pre-tax gains on effective cash flow hedges of $1,916$ 1,135 million being deferred within accumulated OCI, including approximately $1,010$757 million related to the financial swap with ComEd. Amounts recorded in accumulated OCI related to changes in energy commodity cash flow hedges are reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs. Reclassifications from OCI are included in operating revenues, purchased power and fuel in Exelon’s and Generation’s Consolidated Statements of Operations, depending on the commodities involved in the hedged transaction. Based on market prices at June 30, 2010,2011, approximately $941$699 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation, including approximately $383$412 million related to the financial swap with ComEd. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices. Generation expects the settlement of the majority of its cash flow hedges, will occur during 2010 through 2012, andincluding the ComEd financial swap contract, will occur during 20102011 through 2013.
Exelon discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item, in the case of forward-starting hedges, or when it is no longer probable that the forecasted transaction will occur. For the three and six months ended June 30, 2011 and 2010, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial.
The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and six months ended June 30, 20102011 and 2009,2010, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.
Total Cash Flow Hedge OCI Activity, | ||||||||||
Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Income Statement | Energy-Related | Total Cash Flow | ||||||||
Three Months Ended June 30, 2010 | Location | Hedges | Hedges | |||||||
Accumulated OCI derivative gain at March 31, 2010 | $ | 1,703 | (a) | $ | 934 | |||||
Effective portion of changes in fair value | (335 | )(b) | (262 | )(e) | ||||||
Reclassifications from accumulated OCI to net income | Operating Revenue | (211 | )(c) | (148 | ) | |||||
Ineffective portion recognized in income | Purchased Power | 1 | 1 | |||||||
Accumulated OCI derivative gain at June 30, 2010 | $ | 1,158 | (a)(d) | $ | 525 | |||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Three Months Ended June 30, 2011 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at March 31, | $ | 941 | (a) | $ | 354 | |||||
Effective portion of changes in fair value | (106 | )(b) | (64 | ) | ||||||
Reclassifications from accumulated OCI to | Operating Revenue | (143 | )(c) | (77 | ) | |||||
Ineffective portion recognized in income | Purchased Power | (4 | ) | (4 | ) | |||||
Accumulated OCI derivative gain at June 30, | $ | 688 | (a)(d) | $ | 209 | |||||
(a) | Includes $458 million and $562 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $2 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and March 31, 2011, respectively. |
(b) | Includes $39 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract. |
(c) | Includes a $65 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the three months ended June 30, 2011. |
(d) | Excludes $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Six Months Ended June 30, 2011 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at December 31, 2010 | $ | 1,011 | (a) | $ | 400 | |||||
Effective portion of changes in fair value | (43 | )(b) | (46 | ) | ||||||
Reclassifications from accumulated OCI to | Operating Revenue | (275 | )(c) | (140 | ) | |||||
Ineffective portion recognized in income | Purchased Power | (5 | ) | (5 | ) | |||||
Accumulated OCI derivative gain at June 30, | $ | 688 | (a)(d) | $ | 209 | |||||
(a) | Includes $458 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and December 31, 2010. |
(b) | Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the six months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract. |
(c) | Includes a $133 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd and a $2 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the six months ended June 30, 2011. |
(d) | Excludes $2 million of gains, net of taxes, related to interest rate swaps. |
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Three Months Ended June 30, 2010 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at March 31, 2010 | $ | 1,703 | (a) | $ | 934 | |||||
Effective portion of changes in fair value | (335 | )(b) | (262 | ) | ||||||
Reclassifications from accumulated OCI to net income | Operating Revenue | (211 | )(c) | (148 | ) | |||||
Ineffective portion recognized in income | Purchased Power | 1 | 1 | (e) | ||||||
Accumulated OCI derivative gain at June 30, 2010 | $ | 1,158 | (a)(d) | $ | 525 | |||||
(a) | Includes $610 million and $746 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $3 million and $4 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and March 31, 2010, respectively. |
(b) | Includes a $73 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the three months ended June 30, 2010. | |
(c) | Includes a $63 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended June 30, 2010. | |
(d) | Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010. | |
(e) | Includes a $4 million |
60
(Dollars in millions, except per share data, unless otherwise noted)
Total Cash Flow Hedge OCI Activity, | ||||||||||
Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Income Statement | Energy-Related | Total Cash Flow | ||||||||
Six Months Ended June 30, 2010 | Location | Hedges | Hedges | |||||||
Accumulated OCI derivative gain at December 31, 2009 | $ | 1,152 | (a) | $ | 551 | |||||
Effective portion of changes in fair value | 334 | (b) | 205 | (e) | ||||||
Reclassifications from accumulated OCI to net income | Operating Revenue | (328 | )(c) | (231 | ) | |||||
Accumulated OCI derivative gain at June 30, 2010 | $ | 1,158 | (a,d) | $ | 525 | |||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Six Months Ended June 30, 2010 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at December 31, | $ | 1,152 | (a) | $ | 551 | |||||
Effective portion of changes in fair value | 334 | (b) | 205 | (e) | ||||||
Reclassifications from accumulated OCI to | Operating Revenue | (328 | )(c) | (231 | ) | |||||
Accumulated OCI derivative gain at June 30, | $ | 1,158 | (a)(d) | $ | 525 | |||||
(a) | Includes $610 million and $585 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2010 and December 31, 2009, respectively, and $3 million and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and December 31, 2009, respectively. | |
(b) | Includes a $122 million | |
(c) | Includes a $97 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the six months ended June 30, 2010. | |
(d) | Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010. | |
(e) | Includes a $4 million |
Total Cash Flow Hedge OCI Activity, | ||||||||||
Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Income Statement | Energy-Related | Total Cash Flow | ||||||||
Three Months Ended June 30, 2009 | Location | Hedges | Hedges | |||||||
Accumulated OCI derivative gain at March 31, 2009 | $ | 1,814 | (a) | $ | 1,110 | |||||
Effective portion of changes in fair value | (42 | )(b) | 4 | |||||||
Reclassifications from accumulated OCI to net income | Operating Revenue | (262 | )(c) | (226 | ) | |||||
Ineffective portion recognized in income | Purchased Power | 2 | 2 | |||||||
Accumulated OCI derivative gain at June 30, 2009 | $ | 1,512 | (a) | $ | 890 | |||||
61
Total Cash Flow Hedge OCI Activity, | ||||||||||
Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Income Statement | Energy-Related | Total Cash Flow | ||||||||
Six Months Ended June 30, 2009 | Location | Hedges | Hedges | |||||||
Accumulated OCI derivative gain at December 31, 2008 | $ | 855 | (a) | $ | 585 | |||||
Effective portion of changes in fair value | 1,059 | (b) | 654 | |||||||
Reclassifications from accumulated OCI to net income | Operating Revenue | (407 | )(c) | (354 | ) | |||||
Ineffective portion recognized in income | Purchased Power | 5 | 5 | |||||||
Accumulated OCI derivative gain at June 30, 2009 | $ | 1,512 | (a) | $ | 890 | |||||
Exelon’s energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $127 million and $231 million pre-tax gain for the three and six months ended June 30, 2011, respectively, and a $245 million and $383 million pre-tax gain for the three and six months ended June 30, 2010, respectively, and a $373 million and $587 million pre-tax gain for the three and six months ended June 30, 2009, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were increases of $6 million and $1 million pre-tax for the three months ended June 30, 2010,2011 and $3 million and $8 million pre-tax for the three and six months ended June 30, 2009,2010, respectively. The change in cash flow hedge ineffectiveness for the six months ended
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
June 30, 2011 was an increase of $8 million, and for June 30, 2010 was not significant.
Other Derivatives (Exelon and Generation).Other derivative contracts are those that do not qualify or are not designated for hedge accounting. These instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and forward sales. For the three and six months ended June 30, 20102011 and 2009,2010, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
Exelon and Generation | ||||||||||||
Three Months Ended June 30, 2011 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | (21 | ) | $ | 17 | $ | (4 | ) | ||||
Reclassification to realized at settlement | (79 | ) | (47 | ) | (126 | ) | ||||||
Net mark-to-market (losses) | $ | (100 | ) | $ | (30 | ) | $ | (130 | ) | |||
Exelon and Generation | ||||||||||||
Six Months Ended June 30, 2011 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | (20 | ) | $ | 13 | $ | (7 | ) | ||||
Reclassification to realized at settlement | (177 | ) | (96 | ) | (273 | ) | ||||||
Net mark-to-market (losses) | $ | (197 | ) | $ | (83 | ) | $ | (280 | ) | |||
Exelon and Generation | ||||||||||||
Three Months Ended June 30, 2010 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | (72 | ) | $ | 25 | $ | (47 | ) | ||||
Reclassification to realized at settlement | (77 | ) | 1 | (76 | ) | |||||||
Net mark-to-market gains (losses) | $ | (149 | ) | $ | 26 | $ | (123 | ) | ||||
Exelon and Generation | ||||||||||||
Six Months Ended June 30, 2010 | Purchased Power | Fuel | Total | |||||||||
Change in fair value | $ | 181 | $ | 73 | $ | 254 | ||||||
Reclassification to realized at settlement | (146 | ) | 1 | (145 | ) | |||||||
Net mark-to-market gains | $ | 35 | $ | 74 | $ | 109 | ||||||
62
Exelon and Generation | ||||||||||||
Purchased | ||||||||||||
Three Months Ended June 30, 2010 | Power | Fuel | Total | |||||||||
Change in fair value | $ | (72 | ) | $ | 25 | $ | (47 | ) | ||||
Reclassification to realized at settlement | (77 | ) | 1 | (76 | ) | |||||||
Net mark-to-market gains (losses) | $ | (149 | ) | $ | 26 | $ | (123 | ) | ||||
Exelon and Generation | ||||||||||||
Purchased | ||||||||||||
Six Months Ended June 30, 2010 | Power | Fuel | Total | |||||||||
Change in fair value | $ | 181 | $ | 73 | $ | 254 | ||||||
Reclassification to realized at settlement | (146 | ) | 1 | (145 | ) | |||||||
Net mark-to-market gains | $ | 35 | $ | 74 | $ | 109 | ||||||
Exelon and Generation | ||||||||||||
Purchased | ||||||||||||
Three Months Ended June 30, 2009 | Power | Fuel | Total | |||||||||
Change in fair value | $ | (114 | ) | $ | (59 | ) | $ | (173 | ) | |||
Reclassification to realized at settlement | (50 | ) | 53 | 3 | ||||||||
Net mark-to-market losses | $ | (164 | ) | $ | (6 | ) | $ | (170 | ) | |||
Exelon and Generation | ||||||||||||
Purchased | ||||||||||||
Six Months Ended June 30, 2009 | Power | Fuel | Total | |||||||||
Change in fair value | $ | 142 | $ | (102 | ) | $ | 40 | |||||
Reclassification to realized at settlement | (96 | ) | 76 | (20 | ) | |||||||
Net mark-to-market gains (losses) | $ | 46 | $ | (26 | ) | $ | 20 | |||||
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
Three Months Ended | Six Months Ended | |||||||||||||||||
Location on Income | June 30, | June 30, | ||||||||||||||||
Statement | 2010 | 2009 | 2010 | 2009 | ||||||||||||||
Change in fair value | Operating Revenue | $ | 19 | $ | 3 | $ | 26 | $ | 3 | |||||||||
Reclassification to realized at settlement | Operating Revenue | (6 | ) | (22 | ) | (12 | ) | (43 | ) | |||||||||
Net mark-to-market gains (losses) | Operating Revenue | $ | 13 | $ | (19 | ) | $ | 14 | $ | (40 | ) | |||||||
Location on Income Statement | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||
Change in fair value | Operating Revenue | $ | 16 | $ | 19 | $ | 19 | $ | 26 | |||||||||||
Reclassification to realized at settlement | Operating Revenue | (7 | ) | (6 | ) | (12 | ) | (12 | ) | |||||||||||
Net mark-to-market gains | Operating Revenue | $ | 9 | $ | 13 | $ | 7 | $ | 14 | |||||||||||
63
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase and normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2010.2011. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs, NYMEX and ICE commodity exchanges, further discussed in Item 3 — Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $44$43 million and $194$43 million, respectively.
Total | Number of | Net Exposure of | ||||||||||||||||||
Exposure | Counterparties | Counterparties | ||||||||||||||||||
Before Credit | Credit | Net | Greater than 10% | Greater than 10% | ||||||||||||||||
Rating as of June 30, 2010 | Collateral | Collateral | Exposure | of Net Exposure | of Net Exposure | |||||||||||||||
Investment grade | $ | 1,301 | $ | 452 | $ | 849 | — | $ | — | |||||||||||
Non-investment grade | 9 | 5 | 4 | — | — | |||||||||||||||
No external ratings | ||||||||||||||||||||
Internally rated — investment grade | 38 | 5 | 33 | — | — | |||||||||||||||
Internally rated — non-investment grade | 1 | 1 | — | — | — | |||||||||||||||
Total | $ | 1,349 | $ | 463 | $ | 886 | — | $ | — | |||||||||||
Net Credit Exposure by Type of Counterparty | As of June 30, 2010 | |||
Financial institutions | $ | 307 | ||
Investor-owned utilities, marketers and power producers | 490 | |||
Coal | 4 | |||
Other | 85 | |||
Total | $ | 886 | ||
Rating as of June 30, 2011 | Total Exposure Before Credit Collateral | Credit Collateral | Net Exposure | Number of Counterparties Greater than 10% of Net Exposure | Net Exposure of Counterparties Greater than 10% of Net Exposure | |||||||||||||||
Investment grade | $ | 1,058 | $ | 280 | $ | 778 | 2 | $ | 190 | |||||||||||
Non-investment grade | 13 | 5 | 8 | — | — | |||||||||||||||
No external ratings | ||||||||||||||||||||
Internally rated — investment grade | 37 | 7 | 30 | — | — | |||||||||||||||
Internally rated — non-investment grade | 4 | 2 | 2 | — | — | |||||||||||||||
Total | $ | 1,112 | $ | 294 | $ | 818 | 2 | $ | 190 | |||||||||||
Net Credit Exposure by Type of Counterparty | As of June 30, 2011 | |||
Financial institutions | $ | 320 | ||
Investor-owned utilities, marketers and power producers | 310 | |||
Energy cooperatives and municipalities | 163 | |||
Other | 25 | |||
Total | $ | 818 | ||
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on the price of energy in the spotforward market prices compared to the benchmark prices. The benchmark prices are the futureforward prices of energy projected through the contract term and are set at the point of contract execution.supplier bid submittals. If the forward market price of energy in the spot market exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of June 30, 2010,2011, ComEd’s net credit exposure to suppliers was immaterial and either did not exceed the allowed unsecured credit levels or did not exceed the allowed unsecured credit levels by an amount necessary to trigger a collateral call.
immaterial.
64
PECO’s supplier master agreements that govern the terms of its DSP Program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from S&P, Fitch or Moody’sthe major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of June 30, 2010,2011, PECO’s net credit exposure to suppliers was immaterial and either did not exceed the allowed unsecured credit levels or did not exceed the allowed unsecured credit levels by an amount necessary to trigger a collateral call.
PECO is permitted to recover its costs of procuring electric generation following the expiration of its electric generation rate caps on December 31, 2010 through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further information.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of June 30, 2010,2011, PECO had credit exposure of $8$13 million under its natural gas supply and asset management agreements.
Collateral and Contingent-Related Features (Exelon, Generation, ComEd, and PECO)
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels and emissions allowances. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Generation also enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearing houses act as the counterparty to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements.
65
Generation entered into similar supplier forward contractsSFCs with othercertain utilities, including PECO, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Under the terms of the five-year financial swap contract between Generation and ComEd, if a party is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contracts,contract, collateral postings will never exceed $200 million from either ComEd or Generation. Beginning in June 2009, underUnder the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of June 30, 2010, there was an immaterial amount of2011, ComEd held both cash collateral and letters of credit posted by energyfor the purpose of collateral from suppliers to ComEd associatedin association with energy procurement contracts. These amounts were not material. Beginning in June 2010, under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, beginning in December 2010, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of June 30, 2011, ComEd held approximately $20 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 2 of the 20092010 Form 10-K for further information.
PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2010,2011, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of June 30, 2010,2011, PECO could have been required to post approximately $46$40 million of collateral to its counterparties.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
Exelon’s interest rate swaps contain provisions that, in the event of a merger, require that Exelon’s debt maintain an investment grade credit rating from Moody’s or S&P. If Exelon’s debt were to fall below investment grade, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of June 30, 2010,2011, Exelon’s interest rate swap was in an asset position, with a fair value of $15$14 million.
Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)
As of June 30, 20102011 and December 31, 2009, $12010, $2 million and $6$1 million, respectively, of cash collateral received was not offset against net derivative positions, because they were not associated with energy-related derivatives.
66
Exelon and ComEd meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
respectively. Under these facilities, Exelon, Generation and PECO may issue letters of credit in the aggregate amount of up to $200 million, $3.5 billion and $300 million, respectively. The credit facilities expire on March 23, 2016, unless extended in accordance with the terms of the agreements. Each credit facility permits the applicable borrower to request two one-year extensions. Each credit facility also allows Exelon, Generation and PECO to request increases in the aggregate commitments up to an additional $250 million, in the case of each of Exelon and PECO, and up to an additional $1 billion in the case of Generation. Any such extensions or increases are subject to the approval of the lenders party to the credit facilities in their sole discretion. Exelon Corporate, Generation and PECO incurred $3 million, $37 million and $4 million, respectively, in costs related to the replacement of their credit facilities. These costs included upfront and arranger fees, as well as other costs such as external legal fees and filing costs. These costs will be amortized to interest expense over the terms of the credit facilities.
As of June 30, 2011, ComEd had access to an unsecured revolving credit facility with aggregate bank commitments of $1 billion that expires on March 25, 2013, unless extended in accordance with its terms. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $1 billion. ComEd may request two additional one-year extensions. In addition, ComEd may request increases in the aggregate bank commitments under its credit facility up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit facility in their sole discretion.
Borrowings under each credit agreement bear interest at a rate selected by the borrower based upon either the prime rate or at a fixed rate for a specified period based upon a LIBOR-based rate. The Exelon, Generation and PECO agreements provide for adders of up to 85 basis points for prime-based borrowings and up to 185 basis points for the LIBOR-based borrowings based upon the credit rating of the borrower. At June 30, 2011, Exelon, Generation and PECO adders were 30, 30 and 10 basis points, respectively, for prime based borrowings and 130, 130 and 110 basis points, respectively, for LIBOR-based borrowings. The ComEd agreement provides adders of up to 137.5 basis points for prime-based borrowings and up to 237.5 basis points for LIBOR-based borrowings to be added, based upon ComEd’s credit rating. At June 30, 2011, ComEd’s adder was 87.5 basis points for prime based borrowings and 187.5 basis points for LIBOR-based borrowings.
Generation, ComEd and PECO had $30 million, $32 million and $32 million, respectively, of additional credit facility agreements with minority and community banks located primarily within ComEd’s and PECO’s service territories. These facilities expire on October 21, 2011 and are solely utilized to issue letters of credit. As of June 30, 2011, letters of credit issued under these agreements totaled $25 million, $21 million and $20 million for Generation, ComEd and PECO, respectively.
Additionally, on November 4, 2010, Generation entered into a bilateral credit facility, which provides for an aggregate commitment of up to $500 million. The effectiveness and full availability of the credit facility were subject to various conditions. On February 22, 2011, Generation satisfied all conditions to the effectiveness and availability of credit under the credit facility for loans and letters of credit in the aggregate maximum amount of $300 million, which is the limit currently authorized by the board of directors of Exelon Corporation for this credit facility. Availability under the bilateral credit facility extends through December 2015 for $150 million of the $300 million commitment and March 2016 for the remaining $150 million. The bilateral credit facility will be used by Generation primarily to meet requirements for letters of credit but also permits cash borrowings at a rate of LIBOR or a base rate, plus an adder of 200 basis points. No cash borrowings are anticipated under the credit facility. In addition, Generation will pay a facility fee, payable on the first day of each calendar quarter at a rate per annum equal to a specified facility fee rate on the total amount of the credit facility regardless of usage.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon, Generation, ComEd and PECO had the following amounts of commercial paper borrowings outstanding at June 30, 2011 and December 31, 2010:
Commercial Paper Borrowings | June 30, 2011 | December 31, 2010 | ||||||
Exelon Corporate | $ | 140 | $ | — | ||||
Generation | — | — | ||||||
ComEd | — | — | ||||||
PECO | — | — |
As of June 30, 2011, there were no borrowings under the Registrants’ credit facilities.
Issuance of Long-Term Debt
During the six months ended June 30, 2011, the following long-term debt was issued:
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | |||||||||||
ComEd | First Mortgage Bonds | 1.625 | % | January 15, 2014 | $ | 600 | Used as an interim source of liquidity for the January 2011 contribution to Exelon-sponsored pension plans in which ComEd participates and for other general corporate purposes. |
During the six months ended June 30, 2010, there were no issuances of long-term debt.
Retirement of Long-Term Debt
During the six months ended June 30, 2011, the following long-term debt was retired:
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | $ | 1 | ||||||||
ComEd | Sinking fund debentures | 4.75 | % | December 1, 2011 | 1 |
During the six months ended June 30, 2010, the following long-term debt was retired:
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
ComEd | Sinking fund debentures | 4.75 | % | December 1, 2011 | $ | 1 | ||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | 1 | |||||||||
Generation | Montgomery County Series 1994 B Tax Exempt Bonds | Variable | June 1, 2029 | 13 | ||||||||||
Generation | Indiana County Series 2003 A Tax Exempt Bonds | Variable | June 1, 2027 | 17 | ||||||||||
Generation | York County Series 1993 A Tax Exempt Bonds | Variable | August 1, 2016 | 19 | ||||||||||
Generation | Salem County 1993 Series A Tax Exempt Bonds | Variable | March 1, 2025 | 23 | ||||||||||
Generation | Delaware County 1993 Series A Tax Exempt Bonds | Variable | August 1, 2016 | 24 | ||||||||||
Generation | Montgomery County Series 1996 A Tax Exempt Bonds | Variable | March 1, 2034 | 34 | ||||||||||
Generation | Montgomery County Series 1994 A Tax Exempt Bonds | Variable | June 1, 2029 | 83 | ||||||||||
Exelon | 2005 Senior Notes | 4.45 | % | June 15, 2010 | 400 | |||||||||
PECO | PETT Transition Bonds | 6.52 | % | September 1, 2010 | 402 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Variable Rate Debt
Under the terms of ComEd’s variable-rate tax-exempt debt agreements, ComEd may be required to repurchase that debt before its stated maturity unless supported by sufficient letters of credit. If ComEd was required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. ComEd has classified amounts outstanding under these debt agreements as long-term debt based on management’s intent and ability to renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under its existing long-term credit facility.
Accounts Receivable Agreement
PECO is party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in its customer accounts receivable designated under the agreement in exchange for proceeds of $225 million, which is classified as a short-term note payable on Exelon’s and PECO’s Consolidated Balance Sheets. As of June 30, 2011 and December 31, 2010, the financial institution’s undivided interest in Exelon’s and PECO’s customer accounts receivable was equivalent to $309 million and $346 million, respectively, which is calculated under the terms of the agreement. Upon termination or liquidation of this agreement, the financial institution is entitled to recover up to $225 million plus the accrued yield payable from its undivided interest in PECO’s receivables. This agreement terminates on September 6, 2011 unless extended in accordance with its terms. As of June 30, 2011, PECO was in compliance with the requirements of the agreement. In the event the agreement is not extended, PECO has sufficient short-term liquidity and may seek alternate financing.
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
For the Three Months Ended June 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | 2.0 | 3.0 | 3.2 | 1.5 | ||||||||||||
Qualified nuclear decommissioning trust fund income | 1.3 | 1.9 | — | — | ||||||||||||
Domestic production activities deduction | (1.0 | ) | (1.5 | ) | — | — | ||||||||||
Tax exempt income | (0.2 | ) | (0.2 | ) | — | — | ||||||||||
Health Care Reform Acts (a) | — | — | (4.8 | ) | — | |||||||||||
Amortization of investment tax credit | (0.2 | ) | (0.2 | ) | (0.4 | ) | (0.3 | ) | ||||||||
Plant basis differences | — | — | 0.2 | (0.1 | ) | |||||||||||
Production tax credits | (0.9 | ) | (1.5 | ) | — | — | ||||||||||
Other | (1.1 | ) | (1.8 | ) | 0.5 | 0.1 | ||||||||||
Effective income tax rate | 34.9 | % | 34.7 | % | 33.7 | % | 36.2 | % | ||||||||
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
For the Six Months Ended June 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | 3.9 | 4.7 | 4.9 | (1.6 | ) | |||||||||||
Qualified nuclear decommissioning trust fund income | 1.8 | 2.6 | — | — | ||||||||||||
Domestic production activities deduction | (1.0 | ) | (1.4 | ) | — | — | ||||||||||
Tax exempt income | (0.1 | ) | (0.2 | ) | — | — | ||||||||||
Health Care Reform Acts(a) | — | — | (2.8 | ) | — | |||||||||||
Amortization of investment tax credit | (0.2 | ) | (0.2 | ) | (0.4 | ) | (0.3 | ) | ||||||||
Plant basis differences | — | — | (0.1 | ) | (0.2 | ) | ||||||||||
Production tax credits | (0.9 | ) | (1.3 | ) | — | — | ||||||||||
Other | (0.8 | ) | (1.4 | ) | 0.3 | (0.2 | ) | |||||||||
Effective income tax rate | 37.7 | % | 37.8 | % | 36.9 | % | 32.7 | % | ||||||||
For the Three Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | 3.3 | 2.9 | 11.2 | (6.8 | ) | |||||||||||
Qualified nuclear decommissioning trust fund income | (6.7 | ) | (10.0 | ) | — | — | ||||||||||
Domestic production activities deduction | (2.4 | ) | (3.4 | ) | — | — | ||||||||||
Tax exempt income | (0.2 | ) | (0.2 | ) | — | — | ||||||||||
Amortization of investment tax credit | (0.3 | ) | (0.2 | ) | (0.4 | ) | (0.5 | ) | ||||||||
Plant basis differences | — | — | (0.4 | ) | 0.4 | |||||||||||
Uncertain tax position remeasurement | — | (14.9 | ) | 47.9 | — | |||||||||||
Other | (0.4 | ) | (0.8 | ) | (0.2 | ) | (0.2 | ) | ||||||||
Effective income tax rate | 28.3 | % | 8.4 | % | 93.1 | % | 27.9 | % | ||||||||
For the Six Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | 3.6 | 4.1 | 7.6 | (6.0 | ) | |||||||||||
Qualified nuclear decommissioning trust fund income | (0.7 | ) | (1.0 | ) | — | — | ||||||||||
Domestic production activities deduction | (2.1 | ) | (2.9 | ) | — | — | ||||||||||
Tax exempt income | (0.2 | ) | (0.2 | ) | — | — | ||||||||||
Health Care Reform Acts(b) | 3.0 | 1.5 | 2.7 | 2.9 | ||||||||||||
Amortization of investment tax credit | (0.2 | ) | (0.2 | ) | (0.4 | ) | (0.4 | ) | ||||||||
Plant basis differences | — | — | (0.2 | ) | 0.2 | |||||||||||
Uncertain tax position remeasurement | — | (4.5 | ) | 18.3 | — | |||||||||||
Other | (0.2 | ) | (0.3 | ) | 0.2 | (0.2 | ) | |||||||||
Effective income tax rate | 38.2 | % | 31.5 | % | 63.2 | % | 31.5 | % | ||||||||
(a) | Includes one-time income tax benefit at ComEd recorded pursuant to the 2010 Rate Case order for the recovery of costs related to the passage of the Health Care Reform Acts in 2010. See Note 3 — Regulatory Matters for additional information. |
(b) | See Note 10 — Retirement Benefits for further discussion regarding the impact of the Health Care Reform Acts on income tax expense. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Accounting for Uncertainty in Income Taxes
Exelon, Generation, ComEd and PECO have $818 million, $696 million, $71 million and $44 million, respectively, of unrecognized tax benefits as of June 30, 2011. Exelon’s, Generation’s, ComEd’s and PECO’s uncertain tax positions have not significantly changed since December 31, 2010. See Note 11 of the 2010 Form 10-K for further discussion of reasonably possible changes that could occur in unrecognized tax benefits during the next twelve months.
Other Income Tax Matters
7.IRS Appeals 1999-2001 (Exelon, ComEd and PECO)
1999 Sale of Fossil Generating Assets (Exelon and ComEd). Exelon, through its ComEd subsidiary, took two positions on its 1999 income tax return to defer approximately $2.8 billion of tax gain on the 1999 sale of ComEd’s fossil generating assets. Exelon deferred approximately $1.6 billion of the gain under the involuntary conversion provisions of the IRC. The remaining approximately $1.2 billion of the gain was deferred by reinvesting the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. Exelon received the IRS audit report for 1999 through 2001, which reflected the full disallowance of the deferral of gain associated with both the involuntary conversion position and the like-kind exchange transaction.
Competitive Transition Charges (Exelon, ComEd, and PECO). Exelon filed refund claims with the IRS taking the position that CTCs collected during ComEd’s and PECO’s transition periods represented compensation for that taking and, accordingly, were excludible from taxable income as proceeds from an involuntary conversion. The tax basis of property acquired with the funds provided by the CTCs would be reduced such that the benefits of the position are temporary in nature. The IRS disallowed the refund claims for the 1999-2001 tax years.
Status of Tax Positions. In the second quarter of 2010, Exelon concluded that it had sufficient new information that a remeasurement of the involuntary conversion and CTC positions was required in accordance with applicable accounting standards. As a result, Exelon recorded $65 million (after-tax) of interest expense, of which $36 million (after-tax) and $22 million (after-tax) were recorded at ComEd and PECO, respectively. ComEd also recorded a current tax expense of $70 million offset with a tax benefit recorded at Generation of $70 million. In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion and CTC positions. The agreement is consistent with IRS Appeals’ second quarter offer to settle the involuntary conversion and CTC positions and also includes IRS Appeals’ agreement to withdraw its assertion of the $110 million substantial understatement penalty with respect to Exelon’s involuntary conversion position. Final resolution of the involuntary conversion and CTC disputes remains subject to finalizing terms and calculations and executing definitive agreements satisfactory to both parties. As a result of the preliminary agreement, Exelon and ComEd eliminated any liability for unrecognized tax benefits associated with the settled positions and established a current tax payable to the IRS.
Under the terms of the preliminary agreement, Exelon estimates that the IRS will assess tax and interest of approximately $300 million in 2011 for the years for which there is a resulting tax deficiency, of which $405 million would be paid by ComEd, $135 million would be received by PECO, $10 million would be paid by Generation and the remainder received by Exelon. These amounts are net of approximately $300 million of refunds due from the settlement of the 2001 tax method of accounting change for certain overhead costs under the SSCM as well as other agreed upon audit adjustments. In order to stop additional interest from accruing on the expected assessment, Exelon made a payment in December 2010 to the IRS of $302 million. Further, Exelon expects to receive additional tax refunds of approximately $270 million between 2011 and 2014, of which $335 million would be received by ComEd, $40 million would be paid by Generation and the remainder paid by Exelon.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon and IRS Appeals to date have failed to reach a settlement with respect to the like-kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal-owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. Exelon continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO and does not believe that the concession demanded by the IRS in its settlement offer reflects the strength of Exelon’s position. IRS Appeals also continues to assert an $86 million penalty for a substantial understatement of tax with respect to the like-kind exchange position.
While Exelon has been and remains willing to settle the issue in a manner generally commensurate with its hazards of litigation, the IRS has thus far been unwilling to settle the issue without requiring a nearly complete concession of the issue by Exelon. Accordingly, to continue to contest the IRS’s disallowance of the like-kind exchange position and its assertion of the $86 million substantial understatement penalty, Exelon expects to initiate litigation in the first half of 2012 after the final resolution of the involuntary conversion and CTC settlement. Given that Exelon has determined settlement is not a realistic outcome, it has assessed, in accordance with applicable accounting standards, whether it will prevail in litigation. While Exelon recognizes the complexity and hazards of this litigation, it believes that it is more likely than not that it will prevail in such litigation and, therefore, eliminated any liability for unrecognized tax benefits. Further, Exelon believes it is unlikely that the penalty assertion will ultimately be sustained. Exelon and ComEd have not recorded a liability for penalties. However, should the IRS prevail in asserting the penalty, it would result in an after-tax charge of $86 million to Exelon’s and ComEd’s results of operations.
As of June 30, 2011, assuming Exelon’s preliminary settlement of the involuntary conversion position is finalized, the potential tax and interest, exclusive of penalties, that could become currently payable in the event of a fully successful IRS challenge to Exelon’s like-kind exchange position could be as much as $840 million, of which $540 million would be paid by ComEd and the remainder by Exelon. If the IRS were to prevail in litigation on the like-kind exchange position, Exelon’s results of operations could be negatively affected due to increased interest expense, as of June 30, 2011, by as much as $240 million (after-tax), of which $180 million would be recorded at ComEd and the remainder by Exelon.
Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount.
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (Exelon and Generation)
During 2008, Generation benefited from a provision in the Energy Policy Act of 2005 which allowed companies an income tax deduction for a “special transfer” of funds from a non-tax qualified NDT fund to a qualified NDT fund. As a result of temporary guidance published by the U.S. Department of Treasury, Generation completed a special transfer in the first quarter of 2008 for tax year 2008. In December 2010, the U.S. Department of Treasury issued final regulations under IRC Section 468A. The final regulations included a transitional relief provision which allowed taxpayers to request permission from the IRS to designate a taxable year, as far back as 2006, during which the special transfer will be deemed to have occurred. Exelon determined, and is confirming with the IRS through the ruling process, that this provision allows a majority of Generation’s 2008 special transfer deduction to be claimed in the 2006 tax year and the remaining portions claimed ratably in taxable years 2007 and 2008. On February 18, 2011, in order to preserve both the ability to designate the special transfer from 2008 to an earlier taxable year and the ability to complete future additional special transfers, Exelon filed ruling requests with the IRS. Exelon has received its first favorable ruling from the IRS in the second quarter of 2011, along with several additional favorable rulings during July 2011, and expects that the remaining rulings to be received will be favorable as well. As a result, Exelon recorded an interest and tax benefit of
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
$43 million, net of tax including the impact on the manufacturer’s deduction, in the second quarter of 2011 related to the special transfer completed in 2008. If additional special transfers are made, Exelon is estimating that it will record an additional interest benefit of up to $6 million (after-tax) in the second half of 2011.
2011 Illinois State Tax Rate Legislation (Exelon, Generation and ComEd)
The Taxpayer Accountability and Budget Stabilization Act, (SB 2505), enacted into law in Illinois on January 13, 2011, increases the corporate tax rate in Illinois from 7.3% to 9.5% for tax years 2011 — 2014, provides for a reduction in the rate from 9.5% to 7.75% for tax years 2015 — 2024 and further reduces the rate from 7.75% to 7.3% for tax years 2025 and thereafter. Pursuant to the rate change, Exelon reevaluated its deferred state income taxes during the first quarter of 2011. Illinois’ corporate income tax rate changes resulted in a charge to state deferred taxes (net of Federal taxes) during the first quarter of 2011 of $7 million, $11 million and $4 million for Exelon, Generation and ComEd, respectively. Exelon’s and ComEd’s charge is net of a regulatory asset of $15 million.
In 2011, the income tax rate change is expected to increase Exelon’s Illinois income tax provision (net of Federal taxes) by approximately $5 million, of which $7 million and $4 million of additional tax relates to Exelon Corporate and Generation, respectively, and a $6 million benefit for ComEd. The 2011 tax benefit at ComEd reflects the impact of a 2011 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010.
Long-Term State Tax Apportionment (Exelon and Generation)
Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon and Generation to update their long-term state tax apportionment include significant changes in tax law, such as the 2011 Illinois State Tax Rate Legislation discussed above. Due to the extent and nature of the operations conducted by Exelon and Generation in Illinois, Exelon and Generation reevaluated their long-term state tax apportionment for Illinois and all other states where they have state income tax obligations. The effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax charge during the first quarter of 2011 of $22 million and $11 million (net of Federal taxes) for Exelon and Generation, respectively.
Pennsylvania Bonus Depreciation (Exelon, Generation and PECO)
Pursuant to authoritative guidance issued by the Pennsylvania Department of Revenue on February 24, 2011, Exelon is permitted to deduct 100% bonus depreciation in Pennsylvania in the year that such depreciation is claimed and allowable for Federal purposes. For Federal purposes, qualifying property placed into service after September 8, 2010, and before January 1, 2012, is eligible for 100% bonus depreciation. During the first quarter of 2011, the bonus depreciation deduction resulted in a benefit of approximately $8 million, $2 million and $6 million associated with property placed in service in 2010 at Exelon, Generation and PECO, respectively.
Accounting for Electric Transmission and Distribution Property Repairs (Exelon, ComEd and PECO)
Exelon currently anticipates that the IRS will issue guidance during the second half of 2011 providing a safe harbor method of tax accounting for electric transmission and distribution property to determine the tax treatment of repair costs for electric transmission and distribution assets. The guidance is expected to allow ComEd and PECO to adopt the year of electing a method change, with the ability to retroactively make a method change for the 2010 tax year. If the guidance is issued consistent with our expectation and ComEd and PECO choose to change to the newly prescribed method, it would result in an earnings benefit at PECO while Generation will
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
incur additional income tax expense due to a decrease in its manufacturer’s deduction, resulting in an overall minimal effect on consolidated earnings. In addition, this change to the newly prescribed method will result in a cash tax benefit at ComEd and PECO, partially offset by a cash tax detriment at Generation.
See Note 3 — Regulatory Matters for discussion regarding the regulatory treatment of PECO’s potential tax benefits from the application of the method change prescribed in the 2010 electric and natural gas distribution rate case settlements.
9. Nuclear Decommissioning (Exelon and Generation)
Nuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates.
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2010 to June 30, 2011:
Exelon and Generation | ||||
Nuclear decommissioning ARO at December 31, 2010(a) | $ | 3,276 | ||
Accretion expense | 100 | |||
Costs incurred to decommission retired plants | (4 | ) | ||
Nuclear decommissioning ARO at June 30, 2011(a) | $ | 3,372 | ||
(a) | Includes $5 million as the current portion of the ARO at June 30, 2011 and December 31, 2010, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. |
Nuclear Decommissioning Trust Fund Investments
Generation will pay for its nuclear decommissioning obligations using trust funds that have been established for this purpose. At June 30, 2011 and December 31, 2010, Exelon and Generation had NDT fund investments totaling $6,699 million and $6,408 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and six months ended June 30, 2011 and 2010:
Exelon and Generation | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 28 | $ | (318 | ) | $ | 140 | $ | (207 | ) | ||||||
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c) | 11 | (94 | ) | 54 | (59 | ) |
(a) | Net unrealized gains and (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets. |
(b) | Excludes $22 million and $45 million of net unrealized gains related to the Zion Station pledged assets for the three and six months ended June 30, 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon and Generation’s Consolidated Balance Sheets. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(c) | Gains and (losses) related to Generation’s NDT funds associated with Non-Regulatory Agreement Units are included within Other, net in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. |
Interest and dividends on NDT fund investments are recognized when earned and included in Other, net in Exelon and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon and Generation’s Consolidated Statements of Operations.
See Note 2 of the 2010 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund the customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning. On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC. (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 12 of the 2010 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. On July 14, 2011, three people filed a purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto.
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers. Generation has retained its obligation to transfer the SNF at Zion Station to the DOE for ultimate disposal and has a liability of approximately $35 million, which is included within the nuclear decommissioning ARO at June 30, 2011.
Generation also has retained a requisite level of NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station. As of June 30, 2011, the carrying value of the Zion Station pledged assets and the payable to Zion Solutions was approximately $804 million and $761 million, respectively. The payable excludes a liability recorded within Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. The current portion of the payable to ZionSolutions, included in other current liabilities within Generation’s Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 was $121 million and $127 million, respectively.
Securities Lending Program. Generation’s NDT funds participate in a securities lending program with the trustees of the funds. The program authorizes the trustees to loan securities that are assets of the trust funds to approved borrowers. Borrowers have the right to sell or re-pledge the loaned securities. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The securities are
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is primarily invested in a short-term collateral fund, but may also be invested in assets with maturities matching, or approximating, the duration of the loan of the related securities. The cash collateral received may not be sold or re-pledged by the trustees unless the borrower defaults. Generation bears the risk of loss with respect to its invested cash collateral. Such losses may result from a decline in fair value of specific investments or liquidity impairments resulting from market conditions. Generation, the trustees and the borrowers have the right to terminate the lending agreement at their discretion, upon which borrowers would return securities to Generation in exchange for their cash collateral. If the short-term collateral funds do not have adequate liquidity, Generation may incur losses upon the withdrawal of amounts from the funds to repay the borrowers’ collateral. Losses recognized by Generation, whether the result of declines in fair value or liquidity impairments, have not been significant to date. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further losses.
In 2008, Generation initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral pools is approximately 14 months. The fair value of securities on loan was approximately $27 million and $51 million at June 30, 2011 and December 31, 2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $26 million at June 30, 2011 and $51 million at December 31, 2010. Generation continues to assess its participation in securities lending programs.
A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trust funds and the trustees in their capacity as security agents. Securities lending income allocated to the NDT funds is included in NDT fund earnings and classified as Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three months ended June 30, 2011 and 2010.
NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. On March 10, 2010, Generation notified the NRC that it had remediated the December 31, 2009 underfunded position of its Byron and Braidwood NDT funds with the establishment of approximately $44 million in parent guarantees in accordance with a plan submitted by Generation to the NRC on July 31, 2009. On May 26, 2010, the NRC notified Generation that while the previously established parent guarantees complied with Generation’s remediation plan, additional parent guarantees may be required to meet the future value of the underfunded position. During the third quarter of 2010, Generation established approximately $175 million in additional parent guarantees.
On March 31, 2011, Generation, within its NRC-required biennial decommissioning funding assurance submission, notified the NRC that parent guarantees are no longer required as a result of the modest recovery in the financial markets, which has improved decommissioning funding levels for Byron and Braidwood. Generation expects to cancel the parent guarantees prior to the end of 2011. As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO nuclear plants, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. See Note 12 of the 2010 Form 10-K for further information on NRC minimum funding requirements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
10. Retirement Benefits (Exelon, Generation, ComEd and PECO)
Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees.
Defined Benefit Pension and Other Postretirement Benefits
During the first quarter of 2010,2011, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2010.2011. This valuation resulted in an increasea decrease to the pension obligations of $13$6 million and a decrease to other postretirement obligations of $18$28 million. Additionally, accumulated other comprehensive loss increaseddecreased by approximately $18$39 million (after tax).
The following tables present the components of Exelon’s net periodic benefit costs for the three and six months ended June 30, 20102011 and 2009.2010. The 20102011 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 8.50%8.00%. The 20102011 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 7.83%7.08%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.
Other Postretirement | ||||||||||||||||
Pension Benefits | Benefits | |||||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Service cost | $ | 49 | $ | 45 | $ | 31 | $ | 28 | ||||||||
Interest cost | 165 | 162 | 53 | 50 | ||||||||||||
Expected return on assets | (200 | ) | (194 | ) | (27 | ) | (23 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 2 | 3 | ||||||||||||
Prior service cost (benefit) | 3 | 3 | (14 | ) | (14 | ) | ||||||||||
Actuarial loss | 63 | 49 | 19 | 22 | ||||||||||||
Net periodic benefit cost | $ | 80 | $ | 65 | $ | 64 | $ | 66 | ||||||||
Other Postretirement | ||||||||||||||||
Pension Benefits | Benefits | |||||||||||||||
Six Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Service cost | $ | 96 | $ | 89 | $ | 62 | $ | 56 | ||||||||
Interest cost | 330 | 325 | 107 | 102 | ||||||||||||
Expected return on assets | (400 | ) | (388 | ) | (54 | ) | (47 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 4 | 5 | ||||||||||||
Prior service cost (benefit) | 7 | 7 | (28 | ) | (28 | ) | ||||||||||
Actuarial loss | 127 | 98 | 37 | 44 | ||||||||||||
Net periodic benefit cost | $ | 160 | $ | 131 | $ | 128 | $ | 132 | ||||||||
Pension Benefits Three Months Ended June 30, | Other Postretirement Benefits Three Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost | $ | 53 | $ | 49 | $ | 35 | $ | 31 | ||||||||
Interest cost | 163 | 165 | 51 | 53 | ||||||||||||
Expected return on assets | (234 | ) | (200 | ) | (28 | ) | (27 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 3 | 2 | ||||||||||||
Prior service cost (benefit) | 3 | 3 | (10 | ) | (14 | ) | ||||||||||
Actuarial loss | 82 | 63 | 17 | 19 | ||||||||||||
Net periodic benefit cost | $ | 67 | $ | 80 | $ | 68 | $ | 64 | ||||||||
Pension Benefits Six Months Ended June 30, | Other Postretirement Benefits Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost | $ | 106 | $ | 96 | $ | 71 | $ | 62 | ||||||||
Interest cost | 325 | 330 | 103 | 107 | ||||||||||||
Expected return on assets | (469 | ) | (400 | ) | (56 | ) | (54 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 5 | 4 | ||||||||||||
Prior service cost (benefit) | 7 | 7 | (19 | ) | (28 | ) | ||||||||||
Actuarial loss | 165 | 127 | 33 | 37 | ||||||||||||
Net periodic benefit cost | $ | 134 | $ | 160 | $ | 137 | $ | 128 | ||||||||
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following amounts were included in capital additions and operating and maintenance expense during the three and six months ended June 30, 20102011 and 2009,2010, for Generation’s, ComEd’s, PECO’s and BSC’s allocated portion of the pension and postretirement benefit plans:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
Pension and Postretirement Benefit Costs | 2010 | 2009 | 2010 | 2009 | ||||||||||||
Generation | $ | 67 | $ | 59 | $ | 134 | $ | 119 | ||||||||
ComEd | 53 | 48 | 106 | 96 | ||||||||||||
PECO | 12 | 12 | 24 | 24 | ||||||||||||
BSC(a) | 12 | 12 | 24 | 24 |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Pension and Postretirement Benefit Costs | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Generation | $ | 61 | $ | 67 | $ | 123 | $ | 134 | ||||||||
ComEd | 54 | 53 | 108 | 106 | ||||||||||||
PECO | 8 | 12 | 16 | 24 | ||||||||||||
BSC(a) | 12 | 12 | 24 | 24 |
(a) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. |
Exelon contributed $2.1 billion to its qualified pension plans in January 2011, representing substantially all currently planned 2011 qualified pension plan contributions, of which Generation, ComEd and PECO contributed $952 million, $871 million and $110 million, respectively. Exelon plans to contribute $11 million to its non-qualified pension plans in 2011, of which Generation, ComEd and PECO will contribute $5 million, $2 million and $1 million, respectively.
67
Plan AssetsNuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates.
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2010 to June 30, 2011:
Exelon and Generation | ||||
Nuclear decommissioning ARO at December 31, 2010(a) | $ | 3,276 | ||
Accretion expense | 100 | |||
Costs incurred to decommission retired plants | (4 | ) | ||
Nuclear decommissioning ARO at June 30, 2011(a) | $ | 3,372 | ||
(a) | Includes $5 million as the current portion of the ARO at June 30, 2011 and December 31, 2010, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. |
Investment Strategy.Nuclear Decommissioning Trust Fund Investments
Generation will pay for its nuclear decommissioning obligations using trust funds that have been established for this purpose. At June 30, 2011 and December 31, 2010, Exelon and Generation had NDT fund investments totaling $6,699 million and $6,408 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and six months ended June 30, 2011 and 2010:
Exelon and Generation | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 28 | $ | (318 | ) | $ | 140 | $ | (207 | ) | ||||||
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c) | 11 | (94 | ) | 54 | (59 | ) |
(a) | Net unrealized gains and (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets. |
(b) | Excludes $22 million and $45 million of net unrealized gains related to the Zion Station pledged assets for the three and six months ended June 30, 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon and Generation’s Consolidated Balance Sheets. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(c) | Gains and (losses) related to Generation’s NDT funds associated with Non-Regulatory Agreement Units are included within Other, net in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. |
Interest and dividends on NDT fund investments are recognized when earned and included in Other, net in Exelon and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon and Generation’s Consolidated Statements of Operations.
See Note 2 of the 2010 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund the customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning. On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC. (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 12 of the 2010 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. On July 14, 2011, three people filed a regular basis, Exelon evaluatespurported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto.
ZionSolutions is subject to certain restrictions on its investment strategyability to ensure that planrequest reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
Generation also has retained a requisite level of NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station. As of June 30, 2011, the carrying value of the Zion Station pledged assets and the payable to Zion Solutions was approximately $804 million and $761 million, respectively. The payable excludes a liability recorded within Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. The current portion of the payable to ZionSolutions, included in other current liabilities within Generation’s Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 was $121 million and $127 million, respectively.
Securities Lending Programs.Program. The majority of the benefit plansGeneration’s NDT funds participate in a securities lending program with the trustees of the plans’ investment trusts.funds. The program authorizes the trustee of the particular trusttrustees to lendloan securities whichthat are assets of the plan,trust funds to approved borrowers. Borrowers have the right to sell or re-pledge the loaned securities. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The loaned securities are
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is primarily invested in a short-term collateral funds comprised primarilyfund, but may also be invested in assets with maturities matching, or approximating, the duration of short term investment vehicles andthe loan of the related securities. The cash collateral received may not be sold or re-pledged by the trustees unless the borrower defaults. Exelon’s benefit plans bearGeneration bears the risk of loss with respect to unfavorable changes in the fair value of theits invested cash collateral. Such losses may result from a decline in the fair value of specific investments or due to liquidity impairments resulting from current market conditions. Exelon,Generation, the trustees and the borrowers have the right to terminate the lending agreement at any time. Intheir discretion, upon which borrowers would return securities to Generation in exchange for their cash collateral. If the eventshort-term collateral funds do not have adequate liquidity, Generation may incur losses upon the withdrawal of termination,amounts from the borrowers must returnfunds to repay the loaned securities or surrender theborrowers’ collateral. Losses recognized by Generation, whether the trust wereresult of declines in fair value or liquidity impairments, have not material during the six months ended June 30, 2010 and 2009.been significant to date. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further losses.
In 2008, ExelonGeneration initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral fundspools is approximately 514 months. The fair value of securities on loan was approximately $121$27 million and $356$51 million at June 30, 20102011 and December 31, 2009,2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $124$26 million at June 30, 20102011 and $365$51 million at December 31, 2009. 2010. Generation continues to assess its participation in securities lending programs.
A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the truststrust funds and the trustees in their capacity as security agents. Exelon continuesSecurities lending income allocated to assessthe NDT funds is included in NDT fund earnings and classified as Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three months ended June 30, 2011 and 2010.
NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its participationlife. On March 10, 2010, Generation notified the NRC that it had remediated the December 31, 2009 underfunded position of its Byron and Braidwood NDT funds with the establishment of approximately $44 million in securities lending programs.
parent guarantees in accordance with a plan submitted by Generation to the NRC on July 31, 2009. On May 26, 2010, the NRC notified Generation that while the previously established parent guarantees complied with Generation’s remediation plan, additional parent guarantees may be required to meet the future value of the underfunded position. During the third quarter of 2010, Generation established approximately $175 million in additional parent guarantees.
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(Dollars in millions, except per share data, unless otherwise noted)
Health Care Reform Legislation10. Retirement Benefits (Exelon, Generation, ComEd and PECO)
Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees.
Defined Benefit Pension and Other Postretirement Benefits
During the first quarter of 2010,2011, Exelon recorded total after-tax chargesreceived an updated valuation of approximately $65 millionits pension and other postretirement benefit obligations to income tax expensereflect actual census data as of January 1, 2011. This valuation resulted in a decrease to reverse deferred tax assets previously established. Of this total, Generation, ComEd and PECO recorded chargesthe pension obligations of $24 million, $11$6 million and $9a decrease to other postretirement obligations of $28 million. Additionally, accumulated other comprehensive loss decreased by approximately $39 million respectively.
The following tables present the Health Care Reform Acts contain other provisions that will impact Exelon’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. Exelon does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its postretirement benefit obligation. Accordingly, a re-measurementcomponents of Exelon’s postretirementnet periodic benefit obligation is not required at this time. However, Exelon will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
Savings Plan Matching Contributions | 2010 | 2009 | 2010 | 2009 | ||||||||||||
Exelon | $ | 20 | $ | 18 | $ | 40 | $ | 36 | ||||||||
Generation | 10 | 9 | 21 | 18 | ||||||||||||
ComEd | 6 | 5 | 11 | 10 | ||||||||||||
PECO | 2 | 2 | 4 | 4 |
Pension Benefits Three Months Ended June 30, | Other Postretirement Benefits Three Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost | $ | 53 | $ | 49 | $ | 35 | $ | 31 | ||||||||
Interest cost | 163 | 165 | 51 | 53 | ||||||||||||
Expected return on assets | (234 | ) | (200 | ) | (28 | ) | (27 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 3 | 2 | ||||||||||||
Prior service cost (benefit) | 3 | 3 | (10 | ) | (14 | ) | ||||||||||
Actuarial loss | 82 | 63 | 17 | 19 | ||||||||||||
Net periodic benefit cost | $ | 67 | $ | 80 | $ | 68 | $ | 64 | ||||||||
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Pension Benefits Six Months Ended June 30, | Other Postretirement Benefits Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost | $ | 106 | $ | 96 | $ | 71 | $ | 62 | ||||||||
Interest cost | 325 | 330 | 103 | 107 | ||||||||||||
Expected return on assets | (469 | ) | (400 | ) | (56 | ) | (54 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 5 | 4 | ||||||||||||
Prior service cost (benefit) | 7 | 7 | (19 | ) | (28 | ) | ||||||||||
Actuarial loss | 165 | 127 | 33 | 37 | ||||||||||||
Net periodic benefit cost | $ | 134 | $ | 160 | $ | 137 | $ | 128 | ||||||||
(Dollars in millions, except per share data, unless otherwise noted)
The following tables present total severance benefits costs, recorded asamounts were included in capital additions and operating and maintenance expense in relation to the announced job reductions, forduring the three and six months ended June 30, 2009:
Severance Benefits | Generation | ComEd | PECO | Other | Exelon | |||||||||||||||
Expense recorded for the three and six months ended June 30, 2009 (a)(b) | $ | 15 | $ | 18 | $ | 5 | $ | 2 | $ | 40 |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Pension and Postretirement Benefit Costs | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Generation | $ | 61 | $ | 67 | $ | 123 | $ | 134 | ||||||||
ComEd | 54 | 53 | 108 | 106 | ||||||||||||
PECO | 8 | 12 | 16 | 24 | ||||||||||||
BSC(a) | 12 | 12 | 24 | 24 |
(a) | These amounts | |
Severance Benefits Obligation | Generation | ComEd | PECO | Other | Exelon | |||||||||||||||
Balance at December 31, 2009 | $ | 3 | $ | 7 | $ | 1 | $ | 8 | $ | 19 | ||||||||||
Cash payments | (2 | ) | (5 | ) | (1 | ) | (2 | ) | (10 | ) | ||||||||||
Balance at June 30, 2010 | $ | 1 | $ | 2 | $ | — | $ | 6 | $ | 9 | ||||||||||
Exelon announcedcontributed $2.1 billion to its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011. The units to be retired are Cromby Generating Station (Cromby) Unit 1 and Unit 2 and Eddystone Generating Station (Eddystone) Unit 1 and Unit 2. These actions were in response to the economic outlook related to the continued operation of these four units. On February 1, 2010, Generation notified PJM that, to the extent the retirement of these units results in reliability impacts, Generation would continue operations beyond its desired deactivation date while construction of the necessary transmission upgrades were made, provided that Exelon receives the required environmental permits and adequate cost-based compensation. On March 2, 2010, PJM determined that transmission reliability upgrades will be necessary to alleviate reliability impacts. During May 2010, PJM updated its analysis and determined that reliability upgrades will be completed to support Generation’s retirement of the units on the following schedule: Cromby Unit 1 and Eddystone Unit 1 on May 31, 2011; Cromby Unit 2 on December 31, 2011; and Eddystone Unit 2 on December 31, 2012. These dates are dependent upon the completion of required transmission reliability upgrades and may be subject to further change. Generation revised the depreciable useful lives for these affected units to reflect the aforementioned anticipated deactivation dates. On June 10, 2010, Generation filed with FERC a reliability-must-run rate schedule providing the terms, conditions and cost-based rates under which Generation will continue to operate the units for reliability purposes beyond their planned May 31, 2011 deactivation date. Under the reliability-must-run rate schedule, which is subject to FERC approval, the total compensation would be approximately $8 million and $3 million of monthly fixed-cost recovery for Generation during the reliability-must-run period for Eddystone Unit 2 and Cromby Unit 2, respectively. Such revenue is intended to recover total expected operating costs, plus a return on net assets, of the two units during the reliability-must-run period. In connection with these retirements, Exelon will eliminate approximately 280 employee positions, the majority of which are located at the units to be retired. Total expected costs for Generation related to the announced retirements is $37 million, which includes $15 million for estimated salary continuance and health and welfare severance benefits, a $17 million write down of inventory and $5 million of shut down costs. Cash payments under this plan beganqualified pension plans in January 2010 and will continue through 2013. Additionally, total expected accelerated depreciation expense is approximately $200 million.
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Exelon and | ||||
Severance Benefits Obligation | Generation | |||
Balance at December 31, 2009 | $ | 7 | ||
Cash payments | (1 | ) | ||
Other adjustments | (2 | ) | ||
Balance at June 30, 2010 | $ | 4 | ||
For the Three Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | 3.3 | 2.9 | 11.2 | (6.8 | ) | |||||||||||
Qualified nuclear decommissioning trust fund losses | (6.7 | ) | (10.0 | ) | — | — | ||||||||||
Domestic production activities deduction | (2.4 | ) | (3.4 | ) | — | — | ||||||||||
Tax exempt income | (0.2 | ) | (0.2 | ) | — | — | ||||||||||
Amortization of investment tax credit | (0.3 | ) | (0.2 | ) | (0.4 | ) | (0.5 | ) | ||||||||
Plant basis differences | — | — | (0.4 | ) | 0.4 | |||||||||||
Uncertain Tax Position Remeasurement | — | (14.9 | ) | 47.9 | — | |||||||||||
Other | (0.4 | ) | (0.8 | ) | (0.2 | ) | (0.2 | ) | ||||||||
Effective income tax rate | 28.3 | % | 8.4 | % | 93.1 | % | 27.9 | % | ||||||||
For the Six Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | 3.6 | 4.1 | 7.6 | (6.0 | ) | |||||||||||
Qualified nuclear decommissioning trust fund losses | (0.7 | ) | (1.0 | ) | — | — | ||||||||||
Domestic production activities deduction | (2.1 | ) | (2.9 | ) | — | — | ||||||||||
Tax exempt income | (0.2 | ) | (0.2 | ) | — | — | ||||||||||
Health Care Reform Legislation (a) | 3.0 | 1.5 | 2.7 | 2.9 | ||||||||||||
Amortization of investment tax credit | (0.2 | ) | (0.2 | ) | (0.4 | ) | (0.4 | ) | ||||||||
Plant basis differences | — | — | (0.2 | ) | 0.2 | |||||||||||
Uncertain Tax Position Remeasurement | — | (4.5 | ) | 18.3 | — | |||||||||||
Other | (0.2 | ) | (0.3 | ) | 0.2 | (0.2 | ) | |||||||||
Effective income tax rate | 38.2 | % | 31.5 | % | 63.2 | % | 31.5 | % | ||||||||
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For the Three Months Ended June 30, 2009 | Exelon | Generation | ComEd | PECO | ||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | — | 0.7 | 4.6 | (4.0 | ) | |||||||||||
Qualified nuclear decommissioning trust fund income | 5.7 | 7.3 | — | — | ||||||||||||
Domestic production activities deduction | (0.9 | ) | (1.1 | ) | — | — | ||||||||||
Tax exempt income | (0.1 | ) | (0.1 | ) | — | — | ||||||||||
Nontaxable postretirement benefits | (0.2 | ) | (0.2 | ) | (0.4 | ) | (0.2 | ) | ||||||||
Amortization of investment tax credit | (0.1 | ) | (0.1 | ) | (0.5 | ) | (0.4 | ) | ||||||||
Plant basis differences | — | — | (0.3 | ) | 0.1 | |||||||||||
Other | 0.2 | (0.6 | ) | 0.2 | (0.1 | ) | ||||||||||
Effective income tax rate | 39.6 | % | 40.9 | % | 38.6 | % | 30.4 | % | ||||||||
For the Six Months Ended June 30, 2009 | Exelon | Generation | ComEd | PECO | ||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||
State income taxes, net of Federal income tax benefit | (0.1 | ) | 0.5 | (0.7 | ) | (5.4 | ) | |||||||||
Qualified nuclear decommissioning trust fund income | 1.9 | 2.6 | — | — | ||||||||||||
Domestic production activities deduction | (1.2 | ) | (1.6 | ) | — | — | ||||||||||
Tax exempt income | (0.1 | ) | (0.2 | ) | — | — | ||||||||||
Nontaxable postretirement benefits | (0.3 | ) | (0.2 | ) | (0.5 | ) | (0.3 | ) | ||||||||
Amortization of investment tax credit | (0.2 | ) | (0.1 | ) | (0.5 | ) | (0.4 | ) | ||||||||
Plant basis differences | — | — | (0.3 | ) | 0.3 | |||||||||||
Other | 0.1 | (0.3 | ) | (0.1 | ) | 0.1 | ||||||||||
Effective income tax rate | 35.1 | % | 35.7 | % | 32.9 | % | 29.3 | % | ||||||||
Unlike the qualified pension plans, Exelon’s Generation’s, ComEd’s and PECO’s uncertain tax positions haveother postretirement plans are not significantly changed since December 31, 2009, except for those relatingsubject to the 1999 sale of fossil generating assets and competitive transition charges discussed below. See Note 10 of the 2009 Form 10-K for further discussion of reasonably possible changes that could occur in our unrecognized tax benefits during the next twelve months.
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respectively.
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Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates.
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 20092010 to June 30, 2010:
Exelon and Generation | ||||
Nuclear decommissioning ARO at December 31, 2009 (a) | $ | 3,260 | ||
Accretion expense | 96 | |||
Costs incurred to decommission retired plants | (7 | ) | ||
Nuclear decommissioning ARO at June 30, 2010 (a) | $ | 3,349 | ||
Exelon and Generation | ||||
Nuclear decommissioning ARO at December 31, 2010(a) | $ | 3,276 | ||
Accretion expense | 100 | |||
Costs incurred to decommission retired plants | (4 | ) | ||
Nuclear decommissioning ARO at June 30, 2011(a) | $ | 3,372 | ||
(a) | Includes |
Nuclear Decommissioning Trust Fund Investments
Generation will pay for its respectivenuclear decommissioning obligations using trust funds that have been established for this purpose. At June 30, 20102011 and December 31, 2009,2010, Exelon and Generation had NDT fund investments totaling $6,498$6,699 million and $6,669$6,408 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and six months ended June 30, 20102011 and 2009:
Exelon and Generation | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net unrealized gains (losses) on decommissioning trust funds — | ||||||||||||||||
Regulatory Agreement Units (a) | $ | (318 | ) | $ | 426 | $ | (207 | ) | $ | 258 | ||||||
Net unrealized gains (losses) on decommissioning trust funds — | ||||||||||||||||
Non-Regulatory Agreement Units (b) | (94 | ) | 115 | (59 | ) | 51 |
Exelon and Generation | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 28 | $ | (318 | ) | $ | 140 | $ | (207 | ) | ||||||
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c) | 11 | (94 | ) | 54 | (59 | ) |
(a) | Net unrealized gains and | |
(b) | Excludes $22 million and $45 million of net unrealized gains related to the Zion Station pledged assets for the three and six months ended June 30, 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon and Generation’s Consolidated Balance Sheets. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(c) | Gains and |
Interest and dividends on NDT fund investments are recognized when earned and included in Other, net in Exelon and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon and Generation’s Consolidated Statements of Operations.
See Note 3 — Regulatory Matters2 of the 2010 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund the customers any decommissioning-related assets in excess of the related decommissioning obligations.
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Generation also has retained a requisite level of NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station. As of June 30, 2011, the carrying value of the Zion Station pledged assets and the payable to Zion Solutions was approximately $804 million and $761 million, respectively. The payable excludes a liability recorded within Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. The current portion of the payable to ZionSolutions, included in other current liabilities within Generation’s Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 was $121 million and $127 million, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is primarily invested in a short-term collateral fund, but may also be invested in assets with maturities matching, or approximating, the duration of the loan of the related securities. The cash collateral received may not be sold or re-pledged by the trustees unless the borrower defaults. Generation bears the risk of loss with respect to its invested cash collateral. Such losses may result from a decline in fair value of specific investments or liquidity impairments resulting from current market conditions. Generation, the trustees and the borrowers have the right to terminate the lending agreement at their discretion, upon which borrowers would return securities to Generation in exchange for their cash collateral. If the short-term collateral funds do not have adequate liquidity, Generation may incur losses upon the withdrawal of amounts from the funds to repay the borrowers’ collateral. Losses recognized by Generation, whether the result of declines in fair value or liquidity impairments, have not been significant to date. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further losses.
In 2008, Generation initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral pools is approximately 614 months. The fair value of securities on loan was approximately $129$27 million and $357$51 million at June 30, 20102011 and December 31, 2009,2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $131$26 million at June 30, 20102011 and $366$51 million at December 31, 2009.2010. Generation continues to assess its participation in securities lending programs.
A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trust funds and the trustees in their capacity as security agents. Securities lending income allocated to the NDT funds is included in NDT fund earnings and classified as Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three and six months ended June 30, 20102011 and 2009.
NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. On March 10, 2010, Generation notified the NRC that it had remediated the December 31, 2009 underfunded position of its Byron and Braidwood NDT funds with the establishment of approximately $44 million in parent guarantees in accordance with a plan submitted by Generation to the NRC on July 31, 2009. On May 26, 2010, the NRC notified Generation that while the previously established parent guarantees complied with Generation’s remediation plan, additional parent guarantees may be required to meet the future value of the underfunded position. During the third quarter of 2010, Generation established approximately $175 million in additional parent guarantees.
On March 31, 2011, Generation, within its NRC-required biennial decommissioning funding assurance submission, notified the NRC that parent guarantees may be required.are no longer required as a result of the modest recovery in the financial markets, which has improved decommissioning funding levels for Byron and Braidwood. Generation is currently in discussionsexpects to cancel the parent guarantees prior to the end of 2011. As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the NRC and expects the matterPAPUC that currently allows amounts to be resolved duringcollected from PECO customers for decommissioning the third quarterformer PECO nuclear plants, the NRC minimum funding status of 2010.those plants could change at subsequent NRC filing dates. See Note 1112 of the 20092010 Form 10-K for further information on NRC minimum funding requirements.
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(Dollars in millions, except per share data, unless otherwise noted)
10. Retirement Benefits (Exelon, Generation, ComEd and PECO)
Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees.
Defined Benefit Pension and Other Postretirement Benefits
During the first quarter of 2011, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2011. This valuation resulted in a decrease to the pension obligations of $6 million and a decrease to other postretirement obligations of $28 million. Additionally, accumulated other comprehensive loss decreased by approximately $39 million (after tax).
The following tables present the components of Exelon’s net periodic benefit costs for the three and six months ended June 30, 2011 and 2010. The 2011 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 8.00%. The 2011 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 7.08%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.
Pension Benefits Three Months Ended June 30, | Other Postretirement Benefits Three Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost | $ | 53 | $ | 49 | $ | 35 | $ | 31 | ||||||||
Interest cost | 163 | 165 | 51 | 53 | ||||||||||||
Expected return on assets | (234 | ) | (200 | ) | (28 | ) | (27 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 3 | 2 | ||||||||||||
Prior service cost (benefit) | 3 | 3 | (10 | ) | (14 | ) | ||||||||||
Actuarial loss | 82 | 63 | 17 | 19 | ||||||||||||
Net periodic benefit cost | $ | 67 | $ | 80 | $ | 68 | $ | 64 | ||||||||
Pension Benefits Six Months Ended June 30, | Other Postretirement Benefits Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost | $ | 106 | $ | 96 | $ | 71 | $ | 62 | ||||||||
Interest cost | 325 | 330 | 103 | 107 | ||||||||||||
Expected return on assets | (469 | ) | (400 | ) | (56 | ) | (54 | ) | ||||||||
Amortization of: | ||||||||||||||||
Transition obligation | — | — | 5 | 4 | ||||||||||||
Prior service cost (benefit) | 7 | 7 | (19 | ) | (28 | ) | ||||||||||
Actuarial loss | 165 | 127 | 33 | 37 | ||||||||||||
Net periodic benefit cost | $ | 134 | $ | 160 | $ | 137 | $ | 128 | ||||||||
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following amounts were included in capital additions and operating and maintenance expense during the three and six months ended June 30, 2011 and 2010, for Generation’s, ComEd’s, PECO’s and BSC’s allocated portion of the pension and postretirement benefit plans:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Pension and Postretirement Benefit Costs | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Generation | $ | 61 | $ | 67 | $ | 123 | $ | 134 | ||||||||
ComEd | 54 | 53 | 108 | 106 | ||||||||||||
PECO | 8 | 12 | 16 | 24 | ||||||||||||
BSC(a) | 12 | 12 | 24 | 24 |
(a) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. |
Exelon contributed $2.1 billion to its qualified pension plans in January 2011, representing substantially all currently planned 2011 qualified pension plan contributions, of which Generation, ComEd and PECO contributed $952 million, $871 million and $110 million, respectively. Exelon plans to contribute $11 million to its non-qualified pension plans in 2011, of which Generation, ComEd and PECO will contribute $5 million, $2 million and $1 million, respectively.
Unlike the qualified pension plans, Exelon’s other postretirement plans are not subject to regulatory minimum contribution requirements. Management considers several factors in determining the level of contributions to Exelon’s other postretirement benefit plans, including levels of benefit claims paid and regulatory implications. Exelon expects to contribute approximately $271 million to the other postretirement benefit plans in 2011, of which Generation, ComEd and PECO expect to contribute $118 million, $105 million and $28 million, respectively.
Plan Assets
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
In the second quarter of 2010, Exelon modified its pension investment strategy in order to reduce the volatility of its pension assets relative to its pension liabilities. As a result of this modification, over time, Exelon determined that it will decrease equity investments and increase investments in fixed income securities and alternative investments in order to achieve a balanced portfolio of risk-reducing and return-seeking assets. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Over the next several years, Exelon expects to migrate to a target asset allocation of approximately 30% public equity investments, 50% fixed income investments and 20% alternative investments. The change in the overall investment strategy would tend to lower the expected rate of return on plan assets in future years as compared to the previous strategy.
Securities Lending Programs. The majority of the benefit plans currently participate in a securities lending program with the trustees of the plans’ investment trusts. Under the program, securities loaned to the trustees are required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received may not be sold or re-pledged by the trustees unless the borrower defaults.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
In 2008, Exelon decided to end its participation in this securities lending program and initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral funds is approximately 10 months. The fair value of securities on loan was approximately $22 million and $46 million at June 30, 2011 and December 31, 2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $23 million at June 30, 2011 and $47 million at December 31, 2010. A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trusts and the trustees in their capacity as security agents.
Health Care Reform Legislation (Exelon, Generation, ComEd and PECO)
In March 2010, the Health Care Reform Acts were signed into law. A number of provisions in the Health Care Reform Acts impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs to the extent an employer’s postretirement health care plan receives Federal subsidies that provide retiree prescription drug benefits at least equivalent to Medicare prescription drug benefits. Although this change does not take effect immediately, the Registrants were required to recognize the full accounting impact in their financial statements in the period in which the legislation was enacted. As a result, in the first quarter of 2010, Exelon recorded total after-tax charges of approximately $65 million to income tax expense to reverse deferred tax assets previously established. Of this total, Generation, ComEd and PECO recorded charges of $24 million, $11 million and $9 million, respectively. Pursuant to ComEd’s 2010 Rate Case order, ComEd was allowed recovery of these costs and established a regulatory asset. See Note 113 — Regulatory Matters for additional information.
401(k) Savings Plan
The Registrants participate in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their income in accordance with specified guidelines. Exelon, Generation, ComEd and PECO match a percentage of the 2009 Form 10-Kemployee contributions up to certain limits. The following table presents the cost of matching contributions to the savings plans for the Registrants during the three and six months ended June 30, 2011 and 2010:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Savings Plan Matching Contributions | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Exelon | $ | 15 | $ | 20 | $ | 34 | $ | 40 | ||||||||
Generation | 8 | 10 | 18 | 21 | ||||||||||||
ComEd | 4 | 6 | 10 | 11 | ||||||||||||
PECO | 2 | 2 | 4 | 4 |
11. Plant Retirements (Exelon and Generation)
On December 8, 2010, in connection with the executed Administrative Consent Order (ACO) with the NJDEP, Exelon announced that Generation will permanently cease generation operations at Oyster Creek in 2019. See Note 13 for additional information regarding accounting implicationsthe closure of Oyster Creek.
In 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011, in response to the economic outlook related to the continued operation of these four units. However, PJM determined that transmission reliability upgrades would be necessary to alleviate reliability impacts and that those upgrades would be completed in a manner that will permit
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation’s retirement of two of the regulatoryunits on that date and two of the units subsequent to May 31, 2011. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired; however, Cromby Unit 2 will retire on December 31, 2011 and Eddystone Unit 2 will retire on May 31, 2012. On May 27, 2011, the FERC approved a settlement providing for a reliability-must-run rate schedule, which defines compensation to be paid to Generation for continuing to operate these units. The monthly fixed-cost recovery during the reliability-must-run period for Eddystone Unit 2 and Cromby Unit 2 is approximately $6 million and $2 million, respectively. Such revenue is intended to recover total expected operating costs, plus a return on net assets, of the two units during the reliability-must-run period. In addition, Generation is reimbursed for variable costs, including fuel, emissions costs, chemicals, auxiliary power and for project investment costs during the reliability-must-run period. Eddystone Unit 2 and Cromby Unit 2 began operating under the reliability-must-run agreement effective June 1, 2011.
In connection with ComEdthe retirement of all four units, Exelon is eliminating 251 employee positions, the majority of which are located at the units to be retired. Total expected costs for nuclear decommissioning.
Since the announced retirements in December 2009, Generation recorded pre-tax expense of $29 million, which included a $12 million charge for estimated salary continuance and health and welfare severance benefits, and $17 million of expense for the write down of inventory recorded within operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations.
During the three and six months ended June 30, 2011, Generation recorded pre-tax expense of $1 million and $3 million, respectively, for estimated salary continuance and health and welfare severance benefits. During the six months ended June 30, 2010, Generation recorded a pre-tax credit of $2 million for a reduction in estimated salary continuance and health and welfare severance benefits.
The following table presents the activity of severance obligations for the announced Cromby and Eddystone retirements from December 31, 2010 through June 30, 2011:
Severance Benefits Obligation | Exelon and Generation | |||
Balance at December 31, 2010 | $ | 7 | ||
Severance charges recorded | 3 | |||
Cash payments | (2 | ) | ||
Balance at June 30, 2011 | $ | 8 | ||
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Earnings per Share
Diluted earnings per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s long-term incentive plans considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net income | $ | 445 | $ | 657 | $ | 1,194 | $ | 1,369 | ||||||||
Average common shares outstanding — basic | 661 | 659 | 661 | 659 | ||||||||||||
Assumed exercise of stock options, performance share awards and restricted stock | 1 | 2 | 1 | 2 | ||||||||||||
Average common shares outstanding — diluted | 662 | 661 | 662 | 661 | ||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income | $ | 620 | $ | 445 | $ | 1,288 | $ | 1,194 | ||||||||
Average common shares outstanding — basic | 663 | 661 | 663 | 661 | ||||||||||||
Assumed exercise of stock options, performance share awards and restricted stock | 1 | 1 | 1 | 1 | ||||||||||||
Average common shares outstanding — diluted | 664 | 662 | 664 | 662 | ||||||||||||
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 10 million and 9 million for the three and six months ended June 30, 2011, respectively, and 9 million and 6 million for the three and six months ended June 30, 2010, respectively, and 6 million and 5 million for the three and six months ended June 30, 2009, respectively.
Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of June 30, 2010.2011. In 2008, Exelon management decided to defer indefinitely any share repurchases.
For information regarding capital commitments at December 31, 2009,2010, see Note 18 of the 20092010 Form 10-K. All significant changes in Exelon’s, Generation’s, ComEd’s and PECO’s commitments from December 31, 2009,2010, and all significant contingencies, are disclosed below.
Energy Commitments
Generation’s, ComEd’s and PECO’s short and long-term commitments relating to the sale and purchase of energy, capacity and transmission rights as of June 30, 20102011 changed from December 31, 20092010 as follows:
Generation’s total commitments for future sales of energy to third parties increased by approximately $27$626 million during the six months ended June 30, 2010,2011, reflecting increases of approximately $428$445 million, $123$431 million, $165 million, $54 million and $40$168 million related to 2011, 2012, 2013, 2014, 2015 and 2013beyond sales commitments, respectively, partially offset by a net decrease of approximately $637 million in 2011 due to the fulfillment of approximately $564 million of 2010 commitments as well as new commitments entered into during the six months ended June 30, 2010.2011. The increases were primarily due to increased overall hedging activity in the normal course of business. See Note 6 -— Derivative Financial Instruments for additional information regarding Generation’s hedging program.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in the normal course of business. A decrease of approximately $154 million was due to the fulfillment of 2010 commitments during the six months ended June 30, 2010. See Note 6 — Derivative Financial Instruments for additional information regarding Generation’s hedging program.
beyond net purchase commitments, respectively, due to overall hedging activity in the normal course of business. A decrease of approximately $181 million related to 2011 commitments was due to the fulfillment of commitments partially offset by new commitments during the six months ended June 30, 2011. See Note 6 — Derivative Financial Instruments for additional information regarding Generation’s hedging program. |
In April 2010,May 2011, the ICC approved procurement contracts that enable ComEd to meet a portion of its customers’ electricity requirements for the period from June 2010 through May 2012.2012 as well as a portion of the requirements for each of the years ending in May 2013 and May 2014. These contracts resulted in an increase in ComEd’s energy commitments of $195$178 million for the remainder of 2010, $2062011, $192 million for 2011 and $152012, $292 million for 2012.2013 and $179 million for 2014. See Note 3 — Regulatory Matters for additional information.
In May 2010, ComEd entered into contracts for the procurement of RECs totaling approximately $10 million. Through June 30, 2010, $1 million had been purchased, with $9 million to be purchased by May 31, 2011. See Note 3 — Regulatory Matters for additional information.
Fuel and Natural Gas Purchase Obligations
Generation’s and PECO’s fuel purchase obligations as of June 30, 20102011 changed from December 31, 20092010 as follows:
Generation’s total fuel purchase obligations for nuclear and fossil generation decreased by approximately $658$766 million during the six months ended June 30, 2010,2011, reflecting a decreaseincreases (decreases) of $604$46 million, $(5) million, $(25) million, $(37) million and $(78) million for 2012, 2013, 2014, 2015 and beyond, respectively, primarily due to changes in pricing of certain fuel procurement contracts. Additionally, 2011 commitments during the six months ended June 30, 2011 decreased by $667 million, primarily due to the fulfillment of fuel procurement contracts.
PECO’s total natural gas purchase obligations increased by approximately $52 million during the six months ended June 30, 2010,2011, reflecting increases of $23$38 million and $29$14 million for the remainder of 20102011 and 2011,2012, respectively, primarily related to increased natural gas purchase commitments made in accordance with PECO’s PAPUC-approved procurement schedule.
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Exelon’s, Generation’s ComEd’s and PECO’sComEd’s commercial and construction commitments as of June 30, 2010,2011, representing commitments potentially triggered by future events changed from December 31, 20092010 as follows:
Exelon’s letters of credit increased $3decreased $84 million due to activity at Generation, ComEd and PECO as discussed below. Guarantees decreasedincreased by $37$173 million predominantly as a result of decreases in Generation’s guaranteesenergy trading activities at Generation as noted below, net of approximately $44 million in parent guarantees issued by Exelon as part of the remediation of the December 31, 2009 underfunded position of Generation’s Byron and Braidwood NDT funds.below. Guarantees decreased by $125 million for 2010, increased by $56$11 million for 2011, throughincreased by $195 million for 2012, decreased by $15$95 million for 2013, throughincreased by $96 million for 2014 and increaseddecreased by $48$12 million for 20152016 and beyond.
Generation’s letters of credit increaseddecreased by $63$79 million and guarantees decreasedincreased by $70$177 million primarily as a result of energy trading activities.
ComEd’s letters of credit to PJM decreased by $55 million. ComEd replaced$5 million primarily due to a decrease in the lettersletter of credit with $120 million of cashrequired as collateral due to favorable carrying costs for cash.ComEd’s workers compensation self-insurance.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
ComEd’s PJM RTEP baseline project commitments decreased by $7 million for 2010 and increased by $5$44 million, $8 million, $1 million, and $4$10 million for 2011, 2012, 2013, and 2012,2014, respectively, and decreased by $12 million for 2015, driven by changes in estimated timing and amount of project spending.
Other Purchase Obligations
Exelon’s, Generation’s, ComEd’s and PECO’s other purchase obligations as of June 30, 2010,2011, which primarily represent commitments for services, materials and information, changed from December 31, 20092010 as follows:
Exelon’s other purchase obligations decreased by $23 million for 2010 and increased by $51 million for 2011 through 2012 and $32 million for 2013 through 2014.
Generation’s other purchase obligations increased by $71 million, $67 million, $49 million, $49 million and $32 million for 2011, 2012, 2013, through 2014.2014 and 2015, respectively.
ComEd’s other purchase obligations (decreased) increased by $(23) million and $1 million for 2011 and 2012, respectively.
PECO’s other purchase obligations decreased by $31 million for 2010 and increased by $15$20 million and $10 million for 2011 throughand 2012, and $4 million for 2013 through 2014.respectively.
Indemnifications Related to Sithe (Exelon and Generation)
On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation consummated the acquisition of Reservoir Capital Group’s 50% interest in Sithe and subsequently sold 100% of Sithe to Dynegy, Inc. (Dynegy).
In connection with the sale, Exelon recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. As of June 30, 2010, Exelon’s accrued liabilities related to these indemnifications and guarantees were $5 million. The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at June 30, 2010.
2011.
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On February 9, 2007, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, sold its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation for $95 million in cash plus certain purchase price adjustments. In connection with the transaction, Generation entered into a guarantee agreement under which Generation guarantees the timely payment of TII’s obligations to the subsidiary of AES Corporation pursuant to the terms of the purchase and sale agreement relating to the sale of TII’s ownership interests. Generation would be required to perform in the event that TII does not pay any obligation covered by the guarantee that is not otherwise subject to a dispute resolution process. Generation’s maximum obligation under the guarantee is $95 million as of June 30, 2010.2011. Generation has not recorded a liability associated with this guarantee. The primary remaining exposures covered by this guarantee expired in part during 2008. Generation expects that the remaining exposure will expire in 2012.
Environmental Issues
Environmental LiabilitiesGeneral.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.
ComEd and PECO have identified 42 and 27 sites, respectively, where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd or PECO is one of several PRPs whichthat may be responsible for ultimate remediation of each location. Of the 42 sites identified by ComEd, the Illinois EPA or U.S. EPA have approved the clean upcleanup of 1112 sites and of the 27 sites identified by PECO, the PA DEP has approved the cleanup of 16 sites. Of the remaining sites identified by ComEd and PECO, 2427 and 9 sites, respectively, are currently under some degree of active study and/or remediation. ComEd and PECO anticipate that the majority of the remediation at these sites will continue through at least 2015 and 2021,2018, respectively. In addition,
During the Registrants are currently involvedfirst quarter of 2011, PECO completed an updated remediation cost estimate analysis for a former MGP site where work is scheduled to begin in a numberfall 2011, which resulted in an increase to its reserve and regulatory asset of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.
As of June 30, 20102011 and December 31, 2009, Exelon, Generation, ComEd and PECO2010, the Registrants had accrued the following undiscounted amounts for environmental liabilities:
Total | ||||||||
Environmental | Portion of Total | |||||||
Investigation and | Related to MGP | |||||||
Remediation | Investigation and | |||||||
June 30, 2010 | Reserve | Remediation | ||||||
Exelon | $ | 170 | $ | 146 | ||||
Generation | 15 | — | ||||||
ComEd | 111 | 104 | ||||||
PECO | 44 | 42 |
Total | ||||||||
Environmental | Portion of Total | |||||||
Investigation and | Related to MGP | |||||||
Remediation | Investigation and | |||||||
December 31, 2009 | Reserve | Remediation | ||||||
Exelon | $ | 175 | $ | 149 | ||||
Generation | 17 | — | ||||||
ComEd | 113 | 107 | ||||||
PECO | 45 | 42 |
June 30, 2011 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||
Exelon | $ | 181 | $ | 156 | ||||
Generation | 16 | — | ||||||
ComEd | 118 | 112 | ||||||
PECO | 47 | 44 | ||||||
December 31, 2010 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||
Exelon | $ | 179 | $ | 156 | ||||
Generation | 15 | — | ||||||
ComEd | 120 | 114 | ||||||
PECO | 44 | 42 |
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Section 316(b) of the Clean Water Act.In July 2004, the U.S. EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act, which requiredAct. Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. The Phase II rule provided each facility with a number of compliance optionsimpacts, and permitted site-specific variances based on a cost-benefit analysis. The requirements were intended to be is
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, Oyster Creek, Peach Bottom, Quad Cities, Salem and Schuylkill. Since promulgation of the rule, Generation has been evaluating compliance options at its affected plants and meeting interim compliance deadlines.
Regulations adopted in 2004 applicable to the U.S. EPA for revisions. By its action, the court invalidated compliance measures whichlarge electric generating stations were supportedwithdrawn by the utility industry because they were cost-effective and provided existing plants with needed flexibilityEPA in selecting the compliance option appropriate to its location and operations. On July 9, 2007 the U.S. EPA formally suspended the Phase II rule.
On March 28, 2011, the EPA issued the proposed regulation. The Courts’ opinions have created significant uncertainty aboutproposal does not require closed cycle cooling (e.g., cooling towers) as the specific nature, scopebest technology available to address impingement and timingentrainment. The proposal provides the state permitting agency with discretion to determine the best technology available to limit entrainment mortality, including application of a cost–benefit test and the final compliance requirements.
On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. The current NRC license for Oyster Creek expires in 2029. In reliance upon Exelon’s determination to cease generation operations no later than December 31, 2019, the NJDEP preliminarily determined that closed cycle cooling is not the best technology available for Oyster Creek given the length of time that would be required to retrofit from the existing once-through cooling system to a closed-cycle cooling system and environmental restoration are the only viable compliance optionslimited life span of the plant after installation of a closed-cycle cooling system. Based on its consideration of these and other factors, in its best professional judgment, NJDEP determined that the existing measures at the plant represent the best technology available for Section 316(b) compliancethe facility’s cooling water intake system.
On December 9, 2010, Generation executed an ACO with the NJDEP regarding Oyster Creek. The ACO sets forth, among other things, the agreement by Generation to permanently cease generation operations at Oyster Creek. In lightCreek if the conditions of the U.S. EPA’s suspensionACO are satisfied. In the ACO, the NJDEP agreed to issue a new draft NPDES permit without a requirement for construction of the Phase II rule, on January 7, 2010,cooling towers or other closed cycle cooling facilities. On June 1, 2011, the NJDEP issued a draft NPDES permit for Oyster Creek that wouldpublic notice and comment by August 1, 2011. The draft permit does not require in the exercise of its best professional judgment, the installation of cooling towers asand is otherwise consistent with the best technology available within seven years after the effective dateterms of the permit.ACO. The ACO applies only to Oyster Creek will continue to operate underbased on its current permit, issued in 1994, untilunique circumstances and does not set any precedent for the draft permit is finalized. Generation believes the regulatory process could take up to two years before a final permit is issued. Should the permit be issued in its current form, Generation estimates it would be required to have cooling towers in operation by 2019.
As a result of the installation of cooling towers. Closuredecision and the ACO, the expected economic useful life of Oyster Creek could result in reliability issueshas been reduced. The financial impacts relate primarily to accelerated depreciation and accretion expense associated with the transmission system.changes in decommissioning assumptions related to Generation’s asset retirement obligation over the remaining expected economic useful life of Oyster Creek. During the six months ended June 30, 2011, Generation believesmade employee retention payments of approximately $14 million that will result in approximately $3 million of expense in each of years 2011 through 2015. During 2010, Generation recorded a $7 million expense related the period allowed for compliance will be sufficient to address any transmission reliability issues before operations at Oyster Creek are shut down. If PJM requiresannounced shutdown. During the plant to operate under a “reliability-must-run” order,six months ended June 30, 2011, Generation would be allowed full recoveryrecorded approximately $1 million of its costs to operate until the transmission issues are resolved.
employee retention expense.
81
(Dollars in millions, except per share data, unless otherwise noted)
In June 2001, the NJDEP issued a renewed NPDES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in July 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NPDES permit while the NPDES permit renewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon’s and Generation’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $500approximately $430 million, based on a 2006 estimate, and couldwould result in increased depreciation expense related to the retrofit investment.
It is contestingunknown at this time whether the requirement to install cooling towers at Oyster Creek through the administrative appeal process and is optimistic that any final regulations or permitspermit will not require closed-cycle cooling at Oyster Creek or Salem. In addition, the economic viability of Generation’s other power generation facilities without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost-benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation.
Given the uncertainties associated with these proceedings and the time required for their resolution,requirements that will be contained in the final rule, Generation cannot predict the eventual outcome of the proceedings or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its generating facilities and its future results of operations, cash flows and financial position.
NuclearConemaugh Station Water Discharge Violation. In April 2007, two environmental groups brought a Clean Water Act citizen suit against the operator of Conemaugh Generating Station Groundwater.In 2005 and 2006, the Illinois EPA issued NOVs to Generation alleging violations of state groundwater standards at the Braidwood, Dresden and Byron generating stations related to tritium leaks at the plants. Tritium is a weak radioactive isotope of hydrogen that is produced and released at all nuclear sites and also is released naturally through the interaction of sunlight and water molecules. In addition, the Illinois Attorney General and the State’s Attorney for the counties in which the plants are located filed civil enforcement lawsuits against Generation. On March 11, 2010, Generation agreed to a settlement of all pending actions related to the leaks. Under the terms of the settlement, Generation paid approximately $1.2 million in(CGS), seeking civil penalties and fundsinjunctive relief for supplemental environmental projectsalleged violations of CGS’s NPDES permit. On March 21, 2011, the court entered a partial summary judgment in the communities whereplaintiffs’ favor, declaring as a matter of law that discharges from CGS had violated the plants are located.
Air.On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO2 and NOx. The Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the Court’s July 11, 2008 opinion. On July 6, 2010, the U.S. EPA published the proposed Transport Rule as the replacement to the CAIR. On July 7, 2011, the U.S. EPA published the final rule, now known as the Cross-State Air Pollution Rule (CSAPR). The CSAPR requires 27 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. The final rule maintains the January 1, 2012 and January 1, 2014 phase-in dates that were in the proposed Transport Rule. However, the CSAPR imposes tighter emissions caps than the proposed Transport Rule and includes six additional states under the summertime NOx reduction requirements. These emissions limits may be further reduced as the U.S. EPA finalizes more restrictive ozone and particulate matter NAAQS in the 2011—2012 timeframe.
Under the CSAPR, Generation units will receive allowances based on historic heat input. Intrastate, and limited interstate, trading of allowances is permitted, subject to certain limitations. The CSAPR restricts entirely
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
the use of pre-2012 allowances. Existing SO2 allowances under the ARP would remain available for use under ARP. As part of normal operations,June 30, 2011, Generation and the operatorshad $4 million of Generation’s co-owned facilities perform ongoing environmental monitoring at all nuclear generating stations. In 2009 and 2010, tritium was detectedemission allowances carried at the Oyster Creek, LaSallelower of weighted average cost or market.
In March 2005, the U.S. EPA finalized the CAMR, which was a national program to cap mercury emissions from fossil-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. The D.C. Circuit Court later vacated the CAMR on the basis that the U.S. EPA had failed to properly de-list mercury as a HAP under Section 112(c)(1) of the Clean Air Act. The result of this decision is that mercury emissions from electric generating stations are subject to the more stringent requirements of maximum achievable control technology applicable to HAPs. In resolution of the CAMR litigation, the U.S. EPA entered into a Consent Decree that required it to propose by March 16, 2011 HAP regulations for emissions from fossil generating stations, and Salemto publish final HAP regulations by November 15, 2011.
On March 16, 2011, the U.S. EPA issued a proposed rule setting national emission standards for HAPs from coal- and oil-fired electric generating stations. Plansfacilities. EPA refers to the rule as “the Toxics Rule.” The Toxics Rule would require coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals from air emissions. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have been implemented to ensuremake capital investments and incur higher operating expenses. It is expected that tritium detectedsmaller, older, uncontrolled units will retire rather than make these investments. Coal units with existing controls that do not meet the Toxics Rule may need to upgrade existing controls or add new controls to comply. Exelon, along with the other co-owners of Conemaugh Generating Station, are evaluating controls needed to comply with the Toxics Rule. EPA’s proposed standards will cause oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies, or retire the units. The nature and extent of future regulatory controls on HAP emissions at electric generation power plants will not be determined until the Toxics Rule is finalized by the EPA in November 2011.
The U.S. EPA has announced that it will complete a review of NAAQS in the 2011 — 2012 timeframe for ozone (nitrogen oxide and volatile organic compounds), particulate matter, nitrogen dioxide, sulfur dioxide, and lead. This review could result in more stringent emissions limits on fossil-fired electric generating stations.
Additionally, as of June 30, 2011, Exelon has a $642 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases extend through 2028-2032. While Exelon currently estimates the value of these plants at the sites does not pose a threat to site employees,end of the public orlease term will be in excess of the environment. No NOVs have been issued in connection with anyrecorded residual lease values, CSAPR and HAP regulations could negatively impact the end-of-lease term values of these matters. At this time Exelon cannot estimate the costs of possible remediation efforts for these matters.
Cotter Corporation.The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the anticipated landfill cover remediation for the site is $37approximately $42 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve excavation of the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
radiological contamination. An excavation remedy would be significantly more expensive than the previously selected additional cover remedy.remedy; however, Generation cannot determine at this time whetherbelieves the alternative remedy will be required, and if it is, Generation’s share of the cost for such alternative remedy.
82
Notices and Finding of Violations Related to Electric Generation Stations.On August 6, 2007, ComEd received ana NOV, addressed to it and Midwest Generation, LLC (Midwest Generation) from the U.S. EPA, alleging that ComEd and Midwest Generation have violated and are continuing to violate several provisions of the Clean Air Act as a result of the modification and/or operation of six electric generation stations located in northern Illinois that have been owned and operated by Midwest Generation since 1999. The U.S. EPA requested information related to the stations in 2003, and ComEd has been cooperating with the U.S. EPA since then. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act.
83
In August 2009, the U.S. Department of JusticeDOJ and the Illinois Attorney General filed a complaint against Midwest Generation with the U.S. District Court for the Northern District of Illinois initiating enforcement proceedings with respect to the alleged Clean Air Act violations set forth in the NOV. Neither ComEd nor Exelon were named as a defendant in this original complaint. In March 2010, the District Court granted Midwest Generation’s partial motion to dismiss all but one of the claims against Midwest Generation. The courtCourt held that Midwest Generation cannot be liable for any alleged violations relating to construction that occurred prior to Midwest Generation’s ownership of the stations. In May 2010, the government plaintiffs filed an amended complaint substantially similar to the original complaint, and added ComEd and EME as defendants. The amended complaint seeks injunctive relief and civil penalties against all defendants, although not all of the claims specifically pertain to ComEd.
In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations with respect to its former generation business. Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the amended complaint, the costs that might be incurred or the amount of indemnity that may be available from Midwest Generation and EME; however, Exelon, Generation and ComEd have concluded that while a loss may be reasonably possible, they believein light of the District Court decision the likelihood of loss is not probable.remote. Therefore, no reserve has been established. Further, Generation believes that it would be reimbursed by Midwest Generation and EME for any losses under the terms of the indemnification agreement, subject to the credit worthiness of Midwest Generation and EME. Exelon, Generation and ComEd cannot predict an estimated amount or range of possible loss.
84
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
International Climate Change Regulation.At the international level, the United States is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) and became effective for signatories on February 16, 2005. The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, the United States agreed to the non-binding Copenhagen Accord at the conclusion of the 15th Conference of the Parties under the UNFCCC. Under the Copenhagen Accord, the United States agreed to undertake a number of voluntary measures, including the establishment of a goal to reduce GHG emissions and contributions toward a fund to assist developing nations to address their GHG emissions. The Conference of the Parties met in Mexico in December 2010 and while some progress was made in the Cancun Agreement, the fundamental issues around GHG emission reductions and a successor to the Kyoto Protocol remain unresolved. The next Conference of the Parties is scheduled for Mexicomeeting will be held in late 2010.
Federal Climate Change Legislation and Regulation.Various stakeholders, including Exelon, legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors are considering ways to address the climate change issue. Mandatory programs to reduce GHG emissions are likely to evolve in the future. If these programs become effective, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or procure emission allowances or credits.
Numerous bills have beenwere introduced in Congress during the 111th Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal Renewable Portfolio Standards. Exelon supportsStandards, but none were passed by both houses of Congress. In reaction to the enactment, through Federal legislation,U.S. EPA’s proposed regulation of a cap-and-trade program for GHG emissions, that is mandatory, economy-wide and designedvarious bills have been introduced in a way to limit potential harm to the economy and protect consumers. Exelon believes that any mechanism for allocation of GHG emission allowances should include significant free grants of allowances to electric (and potentially gas) distribution companies to help offset the cost impact of GHG regulation to the end-use consumer. Over the last few years, Exelon has worked with other businesses and environmental organizations that participate in the United States Climate Action Partnership to support the development of an integrated package of recommendations for the Federal government to address the climate change issue through Federal legislation, including aggressive emission reduction targets for total U.S. emissions and robust cost containment measures to ensure that program costs are reasonable.
such legislation is unknown.
85
The issue of GHG regulation of stationary sources will likely be addressed either under the existing provisions of the Clean Air Act by U.S. EPA regulation, or by new and comprehensive Federal legislation. The Obama administration and the U.S. EPA have stated a preference for addressing the issue through Federal legislation. The extent to which GHG emissions will be regulated is currently unknown; however, potential regulation of GHG emissions from stationary sources could cause Exelon to incur material costs of compliance.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Regional and State Climate Change Legislation and Regulation.At a regional level, on November 15, 2007, six Midwest state Governors (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) signed the Midwestern Greenhouse Gas Accord. Under that Accord, an inter-state work group was formed to establish a Midwestern GHG Reduction Program that will: (1) establish GHG reduction targets and timeframes consistent with member state targets; (2) develop a market-based and multi-sector cap-and-trade program to help achieve GHG reductions; and (3) develop other mechanisms and policies to assist in meeting GHG reduction targets (e.g. a low carbon fuel standard). In May 2010, an advisory group appointed by the Governors issued recommendations, which are now under review bybut no actions have been taken on the Governors.
At the state level, the PCCA was signed into law in Pennsylvania in July 2008. The PCCA requires, among other things, thatthat: a Climate Change Advisory Committee be formed, thatformed; a report on the potential impact of climate change in Pennsylvania be developed, thatdeveloped; the PA DEP develop a GHG inventory for Pennsylvania, thatPennsylvania; a voluntary GHG registry be identified,identified; and that the PA DEP, in consultation with the Climate Change Advisory Committee, develop a Climate Change Action Plan for Pennsylvania to be reviewed with the Pennsylvania General Assembly. The Climate Change Advisory Committee issued its recommendations for an Action Plan for consideration by the Pennsylvania legislature on October 9, 2009 and they are currently being considered by the Pennsylvania legislature.
Litigation Matters
Except to the extent noted below, the circumstances set forth in Note 18 of the 20092010 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.
86
Asbestos Personal Injury Claims.Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material. In the second quarter of 2008, Generation revised the period through which it estimates that claims will be presented from 2030 to 2050.
At June 30, 20102011 and December 31, 2009,2010, Generation had reserved approximately $53 million and $49 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2010,2011, approximately $15 million of this amount related to 171175 open claims presented to Generation, while the remaining $38 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050 based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary. During the three months ended June 30, 2010, Generation increased its reserve by approximately $4 million, primarily due to an increase
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in forecasted claims. Updates to this reserve in 2009 did not result in material adjustments.
Exelon, Generation, ComEd and PECO
General.The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. The Registrants will record a receivable if they expect to recover costs for these contingencies. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse impact on the Registrants’ results of operations, cash flows or financial positions.
Income Taxes
See Note 98 — Income Taxes for information regarding the Registrants’ income tax refund claims and certainuncertain tax positions, including the 1999 sale of fossil generating assets.
Supplemental Statement of Operations Information
The following tables provide additional information about the Registrants’ Consolidated Statements of Operations for the three and six months ended June 30, 20102011 and 2009:
Three Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 279 | $ | 115 | $ | 117 | $ | 42 | ||||||||
Regulatory assets(a) | 240 | — | 14 | 226 | ||||||||||||
Nuclear fuel(b) | 168 | 168 | — | — | ||||||||||||
Asset retirement obligation accretion(c) | 50 | 49 | — | — | ||||||||||||
Total depreciation, amortization and accretion | $ | 737 | $ | 332 | $ | 131 | $ | 268 | ||||||||
Three Months Ended June 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 316 | $ | 138 | $ | 126 | $ | 47 | ||||||||
Regulatory assets | 13 | — | 10 | 3 | ||||||||||||
Nuclear fuel(a) | 181 | 181 | — | — | ||||||||||||
Asset retirement obligation accretion(b) | 52 | 52 | — | — | ||||||||||||
Total depreciation, amortization and accretion | $ | 562 | $ | 371 | $ | 136 | $ | 50 | ||||||||
Six Months Ended June 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 629 | $ | 277 | $ | 248 | $ | 93 | ||||||||
Regulatory assets | 27 | — | 22 | 5 | ||||||||||||
Nuclear fuel(a) | 355 | 355 | — | — | ||||||||||||
Asset retirement obligation accretion(b) | 103 | 103 | — | — | ||||||||||||
Total depreciation, amortization and accretion | $ | 1,114 | $ | 735 | $ | 270 | $ | 98 | ||||||||
Three Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 279 | $ | 115 | $ | 117 | $ | 42 | ||||||||
Regulatory assets(c) | 240 | — | 14 | 226 | ||||||||||||
Nuclear fuel(a) | 168 | 168 | — | — | ||||||||||||
Asset retirement obligation accretion(b) | 50 | 49 | — | — | ||||||||||||
Total depreciation, amortization and accretion | $ | 737 | $ | 332 | $ | 131 | $ | 268 | ||||||||
87
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 558 | $ | 223 | $ | 234 | $ | 85 | ||||||||
Regulatory assets(a) | 475 | — | 27 | 448 | ||||||||||||
Nuclear fuel(b) | 323 | 323 | — | — | ||||||||||||
Asset retirement obligation accretion(c) | 99 | 99 | — | — | ||||||||||||
Total depreciation, amortization and accretion | $ | 1,455 | $ | 645 | $ | 261 | $ | 533 | ||||||||
Three Months Ended June 30, 2009 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 237 | $ | 72 | $ | 112 | $ | 40 | ||||||||
Regulatory assets(a) | 202 | — | 12 | 190 | ||||||||||||
Nuclear fuel(b) | 139 | 139 | — | — | ||||||||||||
Asset retirement obligation accretion(c) | 53 | 53 | — | — | ||||||||||||
Total depreciation, amortization and accretion | $ | 631 | $ | 264 | $ | 124 | $ | 230 | ||||||||
Six Months Ended June 30, 2009 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 475 | $ | 149 | $ | 221 | $ | 80 | ||||||||
Regulatory assets(a) | 400 | — | 25 | 375 | ||||||||||||
Nuclear fuel(b) | 272 | 272 | — | — | ||||||||||||
Asset retirement obligation accretion(c) | 106 | 105 | — | — | ||||||||||||
Total depreciation, amortization and accretion | $ | 1,253 | $ | 526 | $ | 246 | $ | 455 | ||||||||
Six Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 558 | $ | 223 | $ | 234 | $ | 85 | ||||||||
Regulatory assets(c) | 475 | — | 27 | 448 | ||||||||||||
Nuclear fuel(a) | 323 | 323 | — | — | ||||||||||||
Asset retirement obligation accretion(b) | 99 | 99 | — | — | ||||||||||||
Total depreciation, amortization and accretion | $ | 1,455 | $ | 645 | $ | 261 | $ | 533 | ||||||||
(a) | ||
Included in fuel expense on the Registrants’ Consolidated Statements of |
Included in operating and maintenance expense on the Registrants’ Consolidated Statements of |
Three Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds — | ||||||||||||||||
Regulatory Agreement Units (a) | $ | 49 | $ | 49 | $ | — | $ | — | ||||||||
Net realized income on decommissioning trust funds — | ||||||||||||||||
Non-Regulatory Agreement Units (a) | 14 | 14 | — | — | ||||||||||||
Net unrealized losses on decommissioning trust funds — | ||||||||||||||||
Regulatory Agreement Units | (318 | ) | (318 | ) | — | — | ||||||||||
Net unrealized losses on decommissioning trust funds — | ||||||||||||||||
Non-Regulatory Agreement Units | (94 | ) | (94 | ) | — | — | ||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | 215 | 215 | — | — | ||||||||||||
Total decommissioning-related activities | (134 | ) | (134 | ) | — | — | ||||||||||
Net direct financing lease income | 7 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions | — | — | 2 | — | ||||||||||||
Other | 5 | 1 | 6 | (1 | ) | |||||||||||
Other, net | $ | (122 | ) | $ | (133 | ) | $ | 8 | $ | (1 | ) | |||||
(c) | For PECO, primarily reflects CTC amortization. |
Three Months Ended June 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 38 | $ | 38 | $ | — | $ | — | ||||||||
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a) | 16 | 16 | — | — | ||||||||||||
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units | 28 | 28 | — | — | ||||||||||||
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units | 11 | 11 | — | — | ||||||||||||
Net unrealized gains on pledged assets — Zion Station decommissioning | 22 | 22 | — | — | ||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | (70 | ) | (70 | ) | — | — | ||||||||||
Total decommissioning-related activities | 45 | 45 | — | — | ||||||||||||
Investment income | 1 | — | — | 1 | ||||||||||||
Long-term lease income | 7 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions | 43 | 33 | 1 | — | ||||||||||||
AFUDC — Equity | 4 | — | 2 | 2 | ||||||||||||
Other | — | (2 | ) | 1 | — | |||||||||||
Other, net | $ | 100 | $ | 76 | $ | 4 | $ | 3 | ||||||||
88
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds — | ||||||||||||||||
Regulatory Agreement Units(a) | $ | 98 | $ | 98 | $ | — | $ | — | ||||||||
Net realized income on decommissioning trust funds — | ||||||||||||||||
Non-Regulatory Agreement Units(a) | 26 | 26 | — | — | ||||||||||||
Net unrealized losses on decommissioning trust funds — | ||||||||||||||||
Regulatory Agreement Units | (207 | ) | (207 | ) | — | — | ||||||||||
Net unrealized losses on decommissioning trust funds — | ||||||||||||||||
Non-Regulatory Agreement Units | (59 | ) | (59 | ) | — | — | ||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | 87 | 87 | — | — | ||||||||||||
Total decommissioning-related activities | (55 | ) | (55 | ) | — | — | ||||||||||
Net direct financing lease income | 13 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions | — | — | 2 | — | ||||||||||||
Other | 13 | 1 | 9 | 4 | ||||||||||||
Other, net | $ | (29 | ) | $ | (54 | ) | $ | 11 | $ | 4 | ||||||
Six Months Ended June 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 81 | $ | 81 | $ | — | $ | — | ||||||||
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a) | 26 | 26 | — | — | ||||||||||||
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units | 140 | 140 | — | — | ||||||||||||
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units | 54 | 54 | — | — | ||||||||||||
Net unrealized gains on pledged assets-Zion Station decommissioning | 45 | 45 | — | — | ||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | (221 | ) | (221 | ) | — | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total decommissioning-related activities | 125 | 125 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Investment income | 2 | — | — | 2 | ||||||||||||
Long-term lease income | 14 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions | 46 | 33 | 1 | 1 | ||||||||||||
AFUDC — Equity | 9 | — | 4 | 6 | ||||||||||||
Other | (2 | ) | (6 | ) | 3 | (1 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Other, net | $ | 194 | $ | 152 | $ | 8 | $ | 8 | ||||||||
|
|
|
|
|
|
|
|
(a) | Includes investment income and realized gains and losses on sales of investments of the trust funds. | |
(b) | Includes the elimination of NDT |
Three Months Ended June 30, 2009 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds — | ||||||||||||||||
Regulatory Agreement Units (a) | $ | 10 | $ | 10 | $ | — | $ | — | ||||||||
Net realized income on decommissioning trust funds — | ||||||||||||||||
Non-Regulatory Agreement Units (a) | 10 | 10 | — | — | ||||||||||||
Net unrealized gains on decommissioning trust funds — | ||||||||||||||||
Regulatory Agreement Units | 426 | 426 | — | — | ||||||||||||
Net unrealized gains on decommissioning trust funds — | ||||||||||||||||
Non-Regulatory Agreement Units | 115 | 115 | — | — | ||||||||||||
Regulatory offset to decommissioning trust fund-related activities (b) | (349 | ) | (349 | ) | — | — | ||||||||||
Total decommissioning-related activities | 212 | 212 | — | — | ||||||||||||
Net direct financing lease income | 7 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions (c) | 38 | — | 59 | 2 | ||||||||||||
Other-than-temporary impairment to Rabbi trust investments (d) | (7 | ) | — | (7 | ) | — | ||||||||||
Other | 7 | 3 | 3 | 1 | ||||||||||||
Other, net | $ | 257 | $ | 215 | $ | 55 | $ | 3 | ||||||||
Three Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 49 | $ | 49 | $ | — | $ | — | ||||||||
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a) | 14 | 14 | — | — | ||||||||||||
Net unrealized losses on decommissioning trust funds — Regulatory Agreement Units | (318 | ) | (318 | ) | — | — | ||||||||||
Net unrealized losses on decommissioning trust funds — Non-Regulatory Agreement Units | (94 | ) | (94 | ) | — | — | ||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | 215 | 215 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total decommissioning-related activities | (134 | ) | (134 | ) | — | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Long-term lease income | 7 | — | — | — | ||||||||||||
Interest income related to uncertain income tax provisions | — | — | 2 | — | ||||||||||||
Other | 5 | 1 | 6 | (1 | ) | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Other, net | $ | (122 | ) | $ | (133 | ) | $ | 8 | $ | (1 | ) | |||||
|
|
|
|
|
|
|
|
89
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2009 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds — | ||||||||||||||||
Regulatory Agreement Units(a) | $ | 28 | $ | 28 | $ | — | $ | — | ||||||||
Net realized income on decommissioning trust funds — | ||||||||||||||||
Non-Regulatory Agreement Units(a) | 18 | 18 | — | — | ||||||||||||
Net unrealized gains on decommissioning trust funds — | ||||||||||||||||
Regulatory Agreement Units | 258 | 258 | — | — | ||||||||||||
Net unrealized gains on decommissioning trust funds — | ||||||||||||||||
Non-Regulatory Agreement Units | 51 | 51 | — | — | ||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | (234 | ) | (234 | ) | — | — | ||||||||||
Total decommissioning-related activities | 121 | 121 | — | — | ||||||||||||
Investment income | 1 | — | — | 1 | ||||||||||||
Net direct financing lease income | 13 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions (c) | 77 | 4 | 87 | 3 | ||||||||||||
Other-than-temporary impairment to Rabbi trust investments (d) | (7 | ) | — | (7 | ) | — | ||||||||||
Other | 14 | 8 | 7 | 2 | ||||||||||||
Other, net | $ | 219 | $ | 133 | $ | 87 | $ | 6 | ||||||||
Six Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 98 | $ | 98 | $ | — | $ | — | ||||||||
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a) | 26 | 26 | — | — | ||||||||||||
Net unrealized losses on decommissioning trust funds — Regulatory Agreement Units | (207 | ) | (207 | ) | — | — | ||||||||||
Net unrealized losses on decommissioning trust funds — Non-Regulatory Agreement Units | (59 | ) | (59 | ) | — | — | ||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | 87 | 87 | — | — | ||||||||||||
Total decommissioning-related activities | (55 | ) | (55 | ) | — | — | ||||||||||
Long-term lease income | 13 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions | — | — | 2 | — | �� | |||||||||||
Other | 13 | 1 | 9 | 4 | ||||||||||||
Other, net | $ | (29 | ) | $ | (54 | ) | $ | 11 | $ | 4 | ||||||
(a) | Includes investment income and realized gains and losses on sales of investments of the trust funds. | |
(b) | Includes the elimination of NDT | |
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the six months ended June 30, 20102011 and 2009:
Six Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other non-cash operating activities: | ||||||||||||||||
Pension and non-pension postretirement benefits costs | $ | 288 | $ | 134 | $ | 106 | $ | 24 | ||||||||
Provision for uncollectible accounts | 38 | 1 | 16 | 21 | ||||||||||||
Stock-based compensation costs | 27 | — | — | — | ||||||||||||
Other decommissioning-related activity (a) | 31 | 31 | — | — | ||||||||||||
Energy-related options (b) | (36 | ) | (36 | ) | — | — |
Six Months Ended June 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other non-cash operating activities: | ||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 271 | $ | 123 | $ | 108 | $ | 16 | ||||||||
Provision for uncollectible accounts | 45 | — | 18 | 27 | ||||||||||||
Stock-based compensation costs | �� | 43 | — | — | — | |||||||||||
Other decommissioning-related activity(a) | (35 | ) | (35 | ) | — | — | ||||||||||
Energy-related options(b) | 68 | 68 | — | — | ||||||||||||
Amortization of regulatory asset related to debt costs | 11 | — | 9 | 2 | ||||||||||||
Uncollectible accounts recovery, net | 13 | — | 13 | — | ||||||||||||
Discrete impacts from 2010 Rate Case order | (32 | ) | — | (32 | )(c) | — | ||||||||||
Other | (6 | ) | 12 | (1 | ) | (1 | ) | |||||||||
Total other non-cash operating activities | $ | 378 | $ | 168 | $ | 115 | $ | 44 | ||||||||
Changes in other assets and liabilities: | ||||||||||||||||
Under-recovered energy and transmission costs | (99 | ) | — | (82 | ) | (17 | ) | |||||||||
Other current assets | (216 | ) | (91 | ) | (13 | ) | (104 | )(d) | ||||||||
Other noncurrent assets and liabilities | 68 | (17 | ) | 133 | 13 | |||||||||||
Total changes in other assets and liabilities | $ | (247 | ) | $ | (108 | ) | $ | 38 | $ | (108 | ) | |||||
90
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Amortization of regulatory asset related to debt costs | 12 | — | 11 | 2 | ||||||||||||
Accrual for Illinois utility distribution tax refund (c) | (25 | ) | — | (25 | ) | — | ||||||||||
Under-recovered uncollectible accounts, net (d) | (49 | ) | — | (49 | ) | — | ||||||||||
Other | (8 | ) | 3 | 1 | (3 | ) | ||||||||||
Total other non-cash operating activities | $ | 278 | $ | 133 | $ | 60 | $ | 44 | ||||||||
Changes in other assets and liabilities: | ||||||||||||||||
Under/over-recovered energy and transmission costs | 60 | — | 44 | 16 | ||||||||||||
Other current assets | (172 | ) | (57 | ) | 10 | (127 | )(e) | |||||||||
Other noncurrent assets and liabilities | 103 | 23 | 41 | 37 | ||||||||||||
Total changes in other assets and liabilities | $ | (9 | ) | $ | (34 | ) | $ | 95 | $ | (74 | ) | |||||
Six Months Ended June 30, 2009 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other non-cash operating activities: | ||||||||||||||||
Pension and non-pension postretirement benefits costs | $ | 263 | $ | 120 | $ | 96 | $ | 23 | ||||||||
Loss in equity method investments | 14 | 1 | — | 12 | ||||||||||||
Provision for uncollectible accounts | 65 | 3 | 25 | 38 | ||||||||||||
Stock-based compensation costs | 42 | — | — | — | ||||||||||||
Other decommissioning-related activity (a) | (43 | ) | (43 | ) | — | — | ||||||||||
Energy-related options (b) | 31 | 31 | — | — | ||||||||||||
Amortization of regulatory asset related to debt costs | 14 | — | 12 | 2 | ||||||||||||
Amortization of the regulatory liability related to the PURTA tax settlement (f) | (2 | ) | — | — | (2 | ) | ||||||||||
Other-than-temporary impairment to Rabbi trust investments (g) | 7 | — | 7 | — | ||||||||||||
Other | 20 | 1 | 19 | 10 | ||||||||||||
Total other non-cash operating activities | $ | 411 | $ | 113 | $ | 159 | $ | 83 | ||||||||
Changes in other assets and liabilities: | ||||||||||||||||
Under/over-recovered energy and transmission costs | 58 | — | 47 | 11 | ||||||||||||
Other current assets | (150 | ) | (5 | ) | 1 | (137 | )(e) | |||||||||
Other noncurrent assets and liabilities | (105 | ) | (16 | ) | (82 | ) | (2 | ) | ||||||||
Total changes in other assets and liabilities | $ | (197 | ) | $ | (21 | ) | $ | (34 | ) | $ | (128 | ) | ||||
Six Months Ended June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other non-cash operating activities: | ||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 288 | $ | 134 | $ | 106 | $ | 24 | ||||||||
Provision for uncollectible accounts | 38 | 1 | 16 | 21 | ||||||||||||
Stock-based compensation costs | 27 | — | — | — | ||||||||||||
Other decommissioning-related activity(a) | 31 | 31 | — | — | ||||||||||||
Energy-related options(b) | (36 | ) | (36 | ) | — | — | ||||||||||
Amortization of regulatory asset related to debt costs | 12 | — | 11 | 2 | ||||||||||||
Accrual for Illinois utility distribution tax refund(e) | (25 | ) | — | (25 | ) | — | ||||||||||
Uncollectible accounts recovery, net(f) | (49 | ) | — | (49 | ) | — | ||||||||||
Other | (8 | ) | 3 | 1 | (3 | ) | ||||||||||
|
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Total other non-cash operating activities | $ | 278 | $ | 133 | $ | 60 | $ | 44 | ||||||||
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Changes in other assets and liabilities: | ||||||||||||||||
Under/over-recovered energy and transmission costs | 60 | — | 44 | 16 | ||||||||||||
Other current assets | (172 | ) | (57 | ) | 10 | (127 | )(d) | |||||||||
Other noncurrent assets and liabilities | 103 | 23 | 41 | 37 | ||||||||||||
|
|
|
|
|
|
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Total changes in other assets and liabilities | $ | (9 | ) | $ | (34 | ) | $ | 95 | $ | (74 | ) | |||||
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(a) | Includes the elimination of NDT | |
(b) | Includes option premiums reclassified to realized at | |
(c) | In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time net benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon’s 2009 restructuring plan. See Note 3 — Regulatory Matters for more information. |
(d) | Relates primarily to prepaid utility taxes. |
(e) | During the second quarter of 2010, ComEd recorded a reduction of $25 million to taxes other than income to reflect management’s estimate of future refunds for the 2008 and 2009 tax years associated with Illinois’ utility distribution tax based on an analysis of past refunds and interpretations of the Illinois Public |
Includes $70 million of under-recovered uncollectible accounts expense from 2008 and 2009 | ||
DOE Smart Grid Investment Grant (Exelon and PECO). For the six months ended June 30, 2011, Exelon and PECO have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $19 million and reimbursements of $26 million related to PECO’s DOE SGIG. See Note 3 — Regulatory Matters for additional information regarding the DOE SGIG.
91
(Dollars in millions, except per share data, unless otherwise noted)
Generation have included the cash flows associated with the purchase and sale of Repurchase Agreements with a maturity of three months or less on a net basis in ‘Proceeds from NDT fund sales’ within their Consolidated Statements of Cash Flows. Cash flows associated with all other NDT funds investments will continue to be presented on a gross basis. The six months ended June 30, 2010 were adjusted to reflect this change in presentation, which is presented in the following table:
Six Months Ended June 30, 2010 | ||||||||||||
As previously stated | Adjustments | As Adjusted | ||||||||||
Proceeds from NDT fund sales | $ | 12,528 | $ | (10,729 | ) | $ | 1,799 | |||||
Investments in NDT funds | $ | (12,626 | ) | $ | 10,729 | $ | (1,897 | ) |
Supplemental Balance Sheet Information
The following tables provide additional information regarding accumulated depreciationabout assets and liabilities of the allowance for uncollectible accountsRegistrants as of June 30, 20102011 and December 31, 2009:
June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Property, plant and equipment: | ||||||||||||||||
Accumulated depreciation | $ | 9,341 | (a) | $ | 4,395 | (a) | $ | 2,240 | $ | 2,488 | ||||||
Accounts receivable: | ||||||||||||||||
Allowance for uncollectible accounts | 228 | 31 | 83 | 114 |
December 31, 2009 | Exelon | Generation | ComEd | PECO | ||||||||||||
Property, plant and equipment: | ||||||||||||||||
Accumulated depreciation | $ | 9,023 | (b) | $ | 4,214 | (b) | $ | 2,129 | $ | 2,442 | ||||||
Accounts receivable: | ||||||||||||||||
Allowance for uncollectible accounts | 225 | 31 | 77 | 117 |
June 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Property, plant and equipment: | ||||||||||||||||
Accumulated depreciation | $ | 10,490 | (a) | $ | 5,080 | (a) | $ | 2,592 | $ | 2,595 | ||||||
Accounts receivable: | ||||||||||||||||
Allowance for uncollectible accounts | 229 | 30 | 78 | 121 | ||||||||||||
December 31, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Property, plant and equipment: | ||||||||||||||||
Accumulated depreciation | $ | 10,064 | (b) | $ | 4,880 | (b) | $ | 2,428 | $ | 2,531 | ||||||
Accounts receivable: | ||||||||||||||||
Allowance for uncollectible accounts | 228 | 32 | 80 | 116 |
(a) | Includes accumulated amortization of nuclear fuel in the reactor core of | |
(b) | Includes accumulated amortization of nuclear fuel in the reactor core of |
PECO Installment Plan Receivables (Exelon and PECO). PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The receivables balance for installment plans with terms greater than one year was $24 million and $22 million as of June 30, 2011 and December 31, 2010, respectively, net of an allowance for uncollectible accounts of $21 million and $19 million as of June 30, 2011 and December 31, 2010, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 of the 2010 Form 10-K. The increase of $2 million in the allowance for uncollectible accounts from December 31, 2010 to June 30, 2011 is the result of the change in the provision, which is impacted by payments, new agreements, changes in account risk segments and loss factors applied to the risk segments. The allowance for uncollectible accounts balance at June 30, 2011 of $21 million consists of $1 million, $4 million and $16 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2010 of $19 million consists of $1 million, $5 million and $13 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of June 30, 2011 and December 31, 2010 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on their payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 of the 2010 Form 10-K.
The following tables provide information about accumulated OCI (loss) recorded (after tax) within the consolidatedConsolidated Balance Sheets of the Registrants as of June 30, 20102011 and December 31, 2009:
June 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Accumulated other comprehensive income (loss) | ||||||||||||||||
Net unrealized gain (loss) on cash flow hedges | $ | 525 | $ | 1,163 | $ | (4 | ) | $ | — | |||||||
Pension and non-pension postretirement benefit plans | (2,603 | ) | — | — | — | |||||||||||
Total accumulated other comprehensive income (loss) | $ | (2,078 | ) | $ | 1,163 | $ | (4 | ) | $ | — | ||||||
December 31, 2009 | Exelon | Generation | ComEd | PECO | ||||||||||||
Accumulated other comprehensive income (loss) | ||||||||||||||||
Net unrealized gain on cash flow hedges | $ | 551 | $ | 1,157 | $ | — | $ | 1 | ||||||||
Pension and non-pension postretirement benefit plans | (2,640 | ) | — | — | — | |||||||||||
Total accumulated other comprehensive income (loss) | $ | (2,089 | ) | $ | 1,157 | $ | — | $ | 1 | |||||||
June 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Accumulated other comprehensive income (loss) | ||||||||||||||||
Net unrealized gain on cash flow hedges | $ | 209 | $ | 690 | $ | — | $ | — | ||||||||
Pension and non-pension postretirement benefit plans | (2,719 | ) | — | — | — | |||||||||||
Unrealized gain (loss) on marketable securities | 1 | — | (1 | ) | — | |||||||||||
Total accumulated other comprehensive income (loss) | $ | (2,509 | ) | $ | 690 | $ | (1 | ) | $ | — | ||||||
December 31, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Accumulated other comprehensive income (loss) | ||||||||||||||||
Net unrealized gain on cash flow hedges | $ | 400 | $ | 1,013 | $ | — | $ | — | ||||||||
Pension and non-pension postretirement benefit plans | (2,823 | ) | — | — | — | |||||||||||
Unrealized loss on marketable securities | — | — | (1 | ) | — | |||||||||||
Total accumulated other comprehensive income (loss) | $ | (2,423 | ) | $ | 1,013 | $ | (1 | ) | $ | — | ||||||
Exelon has five reportable segments, which include Generation’s three reportable segments consisting of the first quarter of 2010, ExelonMid-Atlantic, Midwest, and Generation concluded that GenerationSouth and West, and ComEd and PECO. ComEd and PECO each represent a single reportable segment; as such, no longer operates as a singleseparate segment information is provided for these Registrants. PECO has two operating segments, electric and gas delivery, which are aggregated into one reportable segment primarily due to a changetheir similar economic characteristics and the regulatory environments in the financial information regularly evaluated by the chief operating decision maker (CODM) in determining resource allocation and assessing performance. Certain regional results of Generation’s power marketing activities are now being provided to the CODM and in other public disclosures. As a result, beginning in the first quarter of 2010, Generation has three reportable segments consisting of Mid-Atlantic, Midwest and South. Consequently, Exelon has five reportable segments consisting of Mid-Atlantic, Midwest, South, ComEd and PECO. Prior period presentation has been adjusted for comparative purposes.
which they operate.
92
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, 20102011 and 20092010 is as follows:
Three Months Ended June 30, 20102011 and 20092010
Intersegment | ||||||||||||||||||||||||
Generation(a) | ComEd | PECO | Other | Eliminations | Exelon | |||||||||||||||||||
Total revenues(b): | ||||||||||||||||||||||||
2010 | $ | 2,353 | $ | 1,499 | $ | 1,269 | $ | 177 | $ | (900 | ) | $ | 4,398 | |||||||||||
2009 | 2,378 | 1,389 | 1,204 | 207 | (1,037 | ) | 4,141 | |||||||||||||||||
Intersegment revenues(c): | ||||||||||||||||||||||||
2010 | $ | 725 | $ | — | $ | 1 | $ | 177 | $ | (900 | ) | $ | 3 | |||||||||||
2009 | 833 | — | 2 | 207 | (1,036 | ) | 6 | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||
2010 | $ | 382 | $ | 9 | $ | 75 | $ | (21 | ) | $ | — | $ | 445 | |||||||||||
2009 | 512 | 116 | 71 | (35 | ) | (7 | ) | 657 | ||||||||||||||||
Total assets: | ||||||||||||||||||||||||
June 30, 2010 | $ | 22,499 | $ | 20,870 | $ | 9,071 | $ | 5,384 | $ | (8,651 | ) | $ | 49,173 | |||||||||||
December 31, 2009 | 22,406 | 20,697 | 9,019 | 6,088 | (9,030 | ) | 49,180 |
Generation(a) | ComEd | PECO | Other | Intersegment Eliminations | Exelon | |||||||||||||||||||
Total revenues(b): | ||||||||||||||||||||||||
2011 | $ | 2,546 | $ | 1,444 | $ | 842 | $ | 187 | $ | (432 | ) | $ | 4,587 | |||||||||||
2010 | 2,353 | 1,499 | 1,269 | 177 | (900 | ) | 4,398 | |||||||||||||||||
Intersegment revenues(c): | ||||||||||||||||||||||||
2011 | $ | 246 | $ | — | $ | — | $ | 186 | $ | (432 | ) | $ | — | |||||||||||
2010 | 725 | — | 1 | 177 | (900 | ) | 3 | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||
2011 | $ | 443 | $ | 114 | $ | 83 | $ | (20 | ) | $ | — | $ | 620 | |||||||||||
2010 | 382 | 9 | 75 | (21 | ) | — | 445 | |||||||||||||||||
Total assets: | ||||||||||||||||||||||||
June 30, 2011 | $ | 25,633 | $ | 22,348 | $ | 8,996 | $ | 5,926 | $ | (10,917 | ) | $ | 51,986 | |||||||||||
December 31, 2010 | 24,534 | 21,652 | 8,985 | 6,651 | (9,582 | ) | 52,240 |
(a) | Generation represents the three segments, Mid-Atlantic, Midwest, and South and West as shown below. Intersegment revenues for the three months ended June 30, | |
(b) | For the three months ended June 30, | |
(c) | The intersegment profit associated with Generation’s sale of AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 2 of the |
Mid-Atlantic | Midwest | South | Other(b) | Generation | ||||||||||||||||
Total revenues(a): | ||||||||||||||||||||
2010 | $ | 751 | $ | 1,383 | $ | 150 | $ | 69 | $ | 2,353 | ||||||||||
2009 | 834 | 1,344 | 171 | 29 | 2,378 | |||||||||||||||
Revenues net of purchased power and fuel expense: | ||||||||||||||||||||
2010 | $ | 583 | $ | 1,016 | $ | (43 | ) | $ | (102 | ) | $ | 1,454 | ||||||||
2009 | 682 | 1,017 | (25 | ) | (187 | ) | 1,487 |
Mid-Atlantic | Midwest | South and West | Other(b) | Generation | ||||||||||||||||
Total revenues(a): |
| |||||||||||||||||||
2011 | $ | 984 | $ | 1,318 | $ | 154 | $ | 90 | $ | 2,546 | ||||||||||
2010 | 751 | 1,383 | 150 | 69 | 2,353 | |||||||||||||||
Revenues net of purchased power and fuel expense: | ||||||||||||||||||||
2011 | $ | 821 | $ | 887 | $ | (11 | ) | $ | (83 | ) | $ | 1,614 | ||||||||
2010 | 583 | 1,016 | (43 | ) | (102 | ) | 1,454 |
(a) | Includes all sales to third parties and affiliated sales to ComEd and PECO. For the three months ended June 30, | |
(b) | Includes retail gas, proprietary trading, compensation under the reliability-must-run rate schedule, other |
93
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 20102011 and 20092010
Intersegment | ||||||||||||||||||||||||
Generation (a) | ComEd | PECO | Other | Eliminations | Consolidated | |||||||||||||||||||
Total revenues(b): | ||||||||||||||||||||||||
2010 | $ | 4,773 | $ | 2,914 | $ | 2,724 | $ | 359 | $ | (1,911 | ) | $ | 8,859 | |||||||||||
2009 | 4,979 | 2,942 | 2,718 | 391 | (2,167 | ) | 8,863 | |||||||||||||||||
Intersegment revenues(c): | ||||||||||||||||||||||||
2010 | $ | 1,552 | $ | 1 | $ | 3 | $ | 358 | $ | (1,911 | ) | $ | 3 | |||||||||||
2009 | 1,777 | 1 | 4 | 391 | (2,167 | ) | 6 | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||
2010 | $ | 943 | $ | 125 | $ | 176 | $ | (50 | ) | $ | — | $ | 1,194 | |||||||||||
2009 | 1,041 | 230 | 183 | (76 | ) | (9 | ) | 1,369 |
Generation(a) | ComEd | PECO | Other | Intersegment Eliminations | Exelon | |||||||||||||||||||
Total revenues(b): |
| |||||||||||||||||||||||
2011 | $ | 5,285 | $ | 2,910 | $ | 1,996 | $ | 373 | $ | (926 | ) | $ | 9,638 | |||||||||||
2010 | 4,773 | 2,914 | 2,724 | 359 | (1,911 | ) | 8,859 | |||||||||||||||||
Intersegment revenues(c): | ||||||||||||||||||||||||
2011 | $ | 552 | $ | 1 | $ | 2 | $ | 373 | $ | (926 | ) | $ | 2 | |||||||||||
2010 | 1,552 | 1 | 3 | 358 | (1,911 | ) | 3 | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||
2011 | $ | 938 | $ | 183 | $ | 210 | $ | (43 | ) | $ | — | $ | 1,288 | |||||||||||
2010 | 943 | 125 | 176 | (50 | ) | — | 1,194 |
(a) | Generation represents the three segments, Mid-Atlantic, Midwest, and South and West as shown below. Intersegment revenues for the six months ended June 30, | |
(b) | For the six months ended June 30, | |
(c) | The intersegment profit associated with Generation’s sale of RECs to ComEd and AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 3 — Regulatory Issues for additional information on RECs and |
Mid-Atlantic | Midwest | South | Other(b) | Generation | ||||||||||||||||
Total revenues(a): | ||||||||||||||||||||
2010 | $ | 1,531 | $ | 2,734 | $ | 298 | $ | 210 | $ | 4,773 | ||||||||||
2009 | 1,687 | 2,793 | 346 | 153 | 4,979 | |||||||||||||||
Revenues net of purchased power and fuel expense: | ||||||||||||||||||||
2010 | $ | 1,197 | $ | 2,010 | $ | (91 | ) | $ | 160 | $ | 3,276 | |||||||||
2009 | 1,377 | 2,090 | (58 | ) | (5 | ) | 3,404 |
Mid-Atlantic | Midwest | South and West | Other(b) | Generation | ||||||||||||||||
Total revenues(a): |
| |||||||||||||||||||
2011 | $ | 2,049 | $ | 2,724 | $ | 292 | $ | 220 | $ | 5,285 | ||||||||||
2010 | 1,531 | 2,734 | 298 | 210 | 4,773 | |||||||||||||||
Revenues net of purchased power and fuel expense: | ||||||||||||||||||||
2011 | $ | 1,737 | $ | 1,851 | $ | (14 | ) | $ | (200 | ) | $ | 3,374 | ||||||||
2010 | 1,197 | 2,010 | (91 | ) | 160 | 3,276 |
(a) | Includes all sales to third parties and affiliated sales to ComEd and PECO. For the six months ended June 30, | |
(b) | Includes retail gas, proprietary trading, compensation under the reliability-must-run rate schedule, other |
16. Subsequent Events (Exelon and ComEd)
94
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Exelon, a utility services holding company, operates through the following principal subsidiaries:
• | Generation,whose business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and competitive retail sales operations. |
• | ComEd,whose business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services in northern Illinois, including the City of Chicago. |
• | PECO,whose business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia. |
Exelon has five reportable segments consisting of the Mid-Atlantic, Midwest, and South and West regions in Generation, and ComEd and PECO. See Note 1415 of the Combined Notes to Consolidated Financial Statements for segment information.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.
Financial Results.All amounts presented below are before the impact of income taxes, except as noted.
Three Months Ended June 30, 20102011 Compared to Three Months Ended June 30, 2009.2010. Exelon’s net income was $620 million for the three months ended June 30, 2011 as compared to $445 million for the three months ended June 30, 2010, as compared to $657 million for the three months ended June 30, 2009, and diluted earnings per average common share were $0.93 for the three months ended June 30, 2011 as compared to $0.67 for the three months ended June 30, 2010.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $91 million primarily related to a decrease in CTC recoveries at PECO of $287 million as a result of the end of the transition period on December 31, 2010. This impact on Exelon’s net income was partially offset by decreased CTC amortization expense discussed below. In addition, Generation’s operating revenue net of purchased power and fuel expense decreased by $129 million in the Midwest at Generation due to lower realized margins for volumes previously sold under the 2006 ComEd auction contracts, lower nuclear volumes and higher congestion costs. Offsetting these unfavorable impacts were increased operating revenues net of purchased power and fuel expense of $238 million in the Mid-Atlantic at Generation due to increased realized margins on volumes previously sold under Generation’s PPA with PECO and $32 million in the South and West at Generation primarily driven by Exelon Wind which was acquired in December 2010 as comparedand higher realized margins due to $0.99 for the three months ended June 30, 2009.
Operating and maintenance expense remained relatively consistent. Increased incremental storm costsincreased by $78 million primarily as a result of $25 million in the ComEd and PECO service territories and increased nuclear refueling outage costs, including the co-owned Salem plant, of $10$45 million relatedat Generation. The increase was also attributable to Generation’s ownership interest in Salemincreased labor, other benefits, contracting and materials expenses of $51 million, including Exelon Wind. These impacts were partially offset by the impactone-time net benefits of $41$32 million related to severance expense recorded in 2009 for the elimination of managementreestablish plant balances and staff positions pursuantto recover previously incurred costs related to Exelon’s 2009 cost savings program.
Depreciation and amortization expense increaseddecreased by $80$190 million primarily due to a scheduled increasedecrease in CTC amortization expense at PECO of $37$223 million in accordance with its 1998 Restructuring Settlement andresulting from the end of the transition period on December 31, 2010, partially offset by increased depreciation expense of $19 million across the operating companies primarily due to ongoing capital expenditures. Exelon’s results were also significantly affectedadditional plant placed in service and the acquisition of Exelon Wind.
Interest expense decreased by unfavorable net NDT activity$93 million primarily due to the impact of $80the 2010 remeasurement of uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets and CTCs collected by PECO, which resulted in interest expense of $59 million and $36 million, respectively. In addition, in 2010 compared to favorable net NDT activity of $125 million in 2009 for Non-Regulatory Agreement Units as a result of unfavorable market performance.
Six Months Ended June 30, 20102011 Compared to Six Months Ended June 30, 2009.2010 Exelon’s net income was $1,288 million for the six months ended June 30, 2011 as compared to $1,194 million for the six months ended June 30, 2010, as compared to $1,369 million for the six months ended June 30, 2009, and diluted earnings per average common share were $1.94 for the six months ended June 30, 2011 as compared to $1.80 for the six months ended June 30, 20102010.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $338 million primarily related to a decrease in CTC recoveries at PECO of $555 million as a result of the end of the transition period on December 31, 2010. This impact on Exelon’s net income was partially offset by decreased CTC amortization expense discussed below. Mark-to-market losses of $272 million in 2011 from Generation’s hedging activities in 2011 compared to $2.07$109 million in mark-to-market gains in 2010 also had an unfavorable impact on Generation’s operating results. In addition, Generation’s operating revenue net of purchased power and fuel expense decreased by $159 million in the Midwest due to decreased realized margins for volumes previously sold under the six months ended June 30, 2009.
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Operating and maintenance expense increased by $213 million primarily as a result of a $64 million increase in uncollectible accounts expense at ComEd principally due to the impact of the recovery rider mechanism being approved by the ICC in 2010. Exelon’s results were also affected by increased labor, other benefits, contracting and materials expenses of $122 million, including Exelon Wind. These impacts were partially offset by one-time net benefits of $32 million to reestablish plant balances and to recover previously incurred costs related to Exelon’s 2009 restructuring plan pursuant to the 2010 ComEd Rate Case order recorded in the second quarter of 2011.
Depreciation and amortization expense decreased by $377 million primarily due to $110a decrease in CTC amortization expense at PECO of $444 million in mark-to-market gains from Generation’s hedging activities in 2010 compared to $12 million in losses in 2009. Exelon also benefitedresulting from the impactend of $34 million of favorable weather conditionsthe transition period on December 31, 2010, partially offset by increased depreciation expense primarily due to additional plant placed in the ComEd and PECO service territories and a decrease of $56 million in costs associated with the Illinois Settlement Legislation, primarily at Generation. Offsetting these favorable impacts were continuing unfavorable market and portfolio conditions of $71 million, increased nuclear fuel costs of $56 million and the impactacquisition of lower nuclear output of $52 million due to increased planned nuclear outage days.
Interest expense decreased by $297$96 million primarily due to the impact of 2009 activities,the 2010 remeasurement of uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets, and CTCs collected by PECO, which resulted in interest expense of $59 million and $36 million, respectively. In addition, in 2011 Exelon recorded interest income and tax benefits of $43 million, net of tax including the $223 million impairment ofimpact on the Handley and Mountain Creek stations and a charge related to severance expense of $41 million for the elimination of management and staff positions pursuant to Exelon’s 2009 cost savings program. In addition, ComEd recorded the reversal of 2008 and 2009 under-collection of annual uncollectible accounts expense of $70 millionmanufacturer’s deduction, due to the February 2010 approval by the ICC of ComEd’s uncollectible accounts expense rider mechanism, partially offset by a one-time contribution of $10 million associated with the ICC’s approval. Decreased operating and maintenance2011 NDT fund special transfer tax deduction. The decrease in interest expense was partially offset by increased planned nuclear outagehigher interest expense of $44 millionat Generation and incremental costs of $36 million related to storms in the ComEd and PECO service territories.
Exelon’s results were also significantly affected by unfavorable net NDT activity of $33 million in 2010 compared to favorable net NDT activity of $69 million in 2009 for Non-Regulatory Agreement Units as a result of unfavorable market performance.
For further detail regarding the financial results for the three and six months ended June 30, 2010,2011, including explanation of the non-GAAP measure revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.
Adjusted (non-GAAP) Operating Earnings.Exelon’s adjusted (non-GAAP) operating earnings for the three months ended June 30, 20102011 were $656$697 million, or $0.99$1.05 per diluted share, compared with adjusted (non-GAAP) operating earnings of $683$656 million, or $1.03$0.99 per diluted share, for the same period in 2009.2010. Exelon’s adjusted (non-GAAP) operating earnings for the six months ended June 30, 20102011 were $1,319$1,476 million, or $1.99$2.22 per diluted share, compared with adjusted (non-GAAP) operating earnings of $1,479$1,319 million, or $2.24$1.99 per diluted share, for the same period in 2009.2010. In addition to net income, Exelon evaluates its operating performance using the measure of adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business.performance. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
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Three Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
Earnings per | Earnings per | |||||||||||||||
(All amounts after tax) | Diluted Share | Diluted Share | ||||||||||||||
Net Income | $ | 445 | $ | 0.67 | $ | 657 | $ | 0.99 | ||||||||
Illinois Settlement Legislation(a) | 4 | 0.01 | 20 | 0.03 | ||||||||||||
Mark-to-Market Impact of Economic Hedging Activities(b) | 75 | 0.11 | 106 | 0.16 | ||||||||||||
Unrealized (Gains) Losses Related to NDT Fund Investments(c) | 53 | 0.08 | (64 | ) | (0.10 | ) | ||||||||||
City of Chicago Settlement with ComEd(d) | 2 | — | — | — | ||||||||||||
Retirement of Fossil Generating Units(e) | 12 | 0.02 | — | — | ||||||||||||
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes(f) | 65 | 0.10 | (66 | ) | (0.10 | ) | ||||||||||
NRG Acquisition Costs(g) | — | — | 6 | 0.01 | ||||||||||||
2009 Restructuring Charges(h) | — | — | 24 | 0.04 | ||||||||||||
Adjusted (non-GAAP) Operating Earnings | $ | 656 | $ | 0.99 | $ | 683 | $ | 1.03 | ||||||||
Six Months Ended June 30, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
Earnings per | Earnings per | |||||||||||||||
(All amounts after tax) | Diluted Share | Diluted Share | ||||||||||||||
Net Income | $ | 1,194 | $ | 1.80 | $ | 1,369 | $ | 2.07 | ||||||||
Illinois Settlement Legislation(a) | 7 | 0.01 | 41 | 0.06 | ||||||||||||
Mark-to-Market Impact of Economic Hedging Activities(b) | (67 | ) | (0.10 | ) | (7 | ) | (0.01 | ) | ||||||||
Unrealized (Gains) Losses Related to NDT Fund Investments(c) | 33 | 0.05 | (32 | ) | (0.05 | ) | ||||||||||
City of Chicago Settlement with ComEd(d) | 2 | — | — | — | ||||||||||||
Retirement of Fossil Generating Units(e) | 20 | 0.03 | — | — | ||||||||||||
Non-Cash Charge Resulting From Health Care Legislation(i) | 65 | 0.10 | — | — | ||||||||||||
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes(f) | 65 | 0.10 | (66 | ) | (0.10 | ) | ||||||||||
NRG Acquisition Costs(g) | — | — | 15 | 0.03 | ||||||||||||
Impairment of Certain Generating Assets(j) | — | — | 135 | 0.20 | ||||||||||||
2009 Restructuring Charges(h) | — | — | 24 | 0.04 | ||||||||||||
Adjusted (non-GAAP) Operating Earnings | $ | 1,319 | $ | 1.99 | $ | 1,479 | $ | 2.24 | ||||||||
Three Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
(All amounts after tax) | Earnings per Diluted Share | Earnings per Diluted Share | ||||||||||||||
Net Income | $ | 620 | $ | 0.93 | $ | 445 | $ | 0.67 | ||||||||
Illinois Settlement Legislation(a) | — | — | 4 | 0.01 | ||||||||||||
Mark-to-Market Impact of Economic Hedging Activities(b) | 75 | 0.12 | 75 | 0.11 | ||||||||||||
Unrealized (Gains) Losses Related to NDT Fund Investments(c) | (6 | ) | (0.01 | ) | 53 | 0.08 | ||||||||||
City of Chicago Settlement with ComEd(d) | — | — | 2 | — | ||||||||||||
Retirement of Fossil Generating Units(e) | 10 | 0.02 | 12 | 0.02 | ||||||||||||
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income(f) | — | — | 65 | 0.10 | ||||||||||||
Recovery of Costs Resulting From Distribution Rate Case Order(g) | (17 | ) | (0.03 | ) | — | — | ||||||||||
Constellation Merger Costs(h) | 15 | 0.02 | — | — | ||||||||||||
Adjusted (non-GAAP) Operating Earnings | $ | 697 | $ | 1.05 | $ | 656 | $ | 0.99 | ||||||||
Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
(All amounts after tax) | Earnings per Diluted Share | Earnings per Diluted Share | ||||||||||||||
Net Income | $ | 1,288 | $ | 1.94 | $ | 1,194 | $ | 1.80 | ||||||||
Illinois Settlement Legislation(a) | — | — | 7 | 0.01 | ||||||||||||
Mark-to-Market Impact of Economic Hedging Activities(b) | 164 | 0.25 | (67 | ) | (0.10 | ) | ||||||||||
Unrealized (Gains) Losses Related to NDT Fund Investments(c) | (30 | ) | (0.04 | ) | 33 | 0.05 | ||||||||||
City of Chicago Settlement with ComEd(d) | — | — | 2 | — | ||||||||||||
Retirement of Fossil Generating Units(e) | 27 | 0.04 | 20 | 0.03 | ||||||||||||
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes(f) | — | — | 65 | 0.10 | ||||||||||||
Non-Cash Charge Resulting From Health Care Legislation(i) | — | — | 65 | 0.10 | ||||||||||||
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation(j) | 29 | 0.04 | — | — | ||||||||||||
Recovery of Costs Resulting From Distribution Rate Case Order(g) | (17 | ) | (0.03 | ) | — | — | ||||||||||
Constellation Merger Costs(h) | 15 | 0.02 | — | — | ||||||||||||
Adjusted (non-GAAP) Operating Earnings | $ | 1,476 | $ | 2.22 | $ | 1,319 | $ | 1.99 | ||||||||
(a) | Reflects credits issued by | |
(b) | Reflects the impact of (gains) losses for the three and six months ended June 30, |
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(c) | Reflects the impact of (gains) losses for the three and six months ended June 30, 2011 (net of taxes of $19 million and $58 million, respectively) and for the three and six months ended 2010 ($(104) million and | |
(d) | Reflects costs for the three months and six months ended June 30, 2010 | |
(e) | Primarily reflects | |
(f) | Reflects the impacts of 2010 remeasurements of income tax uncertainties for the three and six months ended June 30, | |
(g) | Reflects a one-time benefit in the second quarter of 2011 to recover previously incurred costs as a result of the May 2011 ICC rate order (net of taxes of $5 million). See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information. |
(h) | Reflects | |
(i) | Reflects a non-cash charge to income taxes related to the passage of Federal health care legislation, which includes a provision that reduces the deductibility, for Federal income tax purposes, of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. See Note | |
(j) | Reflects a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the |
Outlook for the Remainder of 20102011 and Beyond.
Acquisitions
Proposed Acquisition of Constellation Energy Company. On April 28, 2011, Exelon and Constellation Energy Group, Inc. (Constellation) announced that they signed an agreement and plan of merger to combine the two companies in a stock-for-stock transaction. Under the merger agreement, Constellation’s shareholders will receive 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock. Based on Exelon’s closing share price on April 27, 2011, Constellation shareholders would receive $7.9 billion in total equity value. The resulting company will retain the Exelon name and be headquartered in Chicago.
The transaction must be approved by the shareholders of both Exelon and Constellation. Completion of the transaction is also conditioned upon approval by the FERC, NRC, Maryland Public Service Commission (MDPSC), the New York Public Service Commission, the Public Utility Commission of Texas, and other state and federal regulatory bodies. The companies are committed to mitigating any competitive issues, and have proposed to divest three Constellation generating stations located in PJM, which is the only market where there is a material overlap of generation owned by both companies. These stations, Brandon Shores and H.A. Wagner in Anne Arundel County, Md., and C.P. Crane in Baltimore County, Md., include base-load coal-fired generation units plus associated gas/oil units located at the same sites, and total 2,648 MW of generation capacity. In addition, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), the transaction cannot be completed until Exelon has made required notifications and given certain information and materials to the Federal Trade Commission (FTC) and/or the Antitrust Division of the United States Department of Justice (DOJ) and until specified waiting period requirements have expired. During the second quarter, Exelon and Constellation filed applications with FERC, the MDPSC, the New York State Public Service Commission and
the Public Utility Commission of Texas seeking approval of the transaction. Exelon and Constellation also filed an application with the NRC for indirect transfer of Constellation licenses and filed notifications with the FTC and DOJ in compliance with the requirements of the HSR Act.
Exelon has been named in suits filed in the Circuit Court of Baltimore City, Maryland alleging that individual directors of Constellation breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin a Constellation shareholder vote on the proposed merger until all material information is disclosed and seek rescission of the proposed merger. In addition, they also seek compensatory damages, rescission damages, attorneys’ fees and costs. Exelon intends to vigorously defend these suits. Exelon does not believe these suits will impact the completion of the transaction and are not expected to have a material impact on Exelon’s results of operations.
Through June 30, 2011, Exelon has incurred approximately $24 million of expense associated with the transaction, primarily related to fees incurred as part of the acquisition. Exelon currently estimates the total costs directly related to closing the transaction will be $144 million, which include financial advisor, consultant, legal and SEC registration fees. In addition, Exelon estimates approximately $500 million of additional integration costs, primarily in 2012 and 2013. Such costs are expected to be partially offset by projected merger-related synergies in 2012 and fully offset in 2013 and beyond. As part of the application for approval of the merger by MDPSC, Exelon and Constellation have proposed a package of benefits to Baltimore Gas and Electric Company customers, the City of Baltimore and the state of Maryland, which results in a direct investment in the state of Maryland of more than $250 million. Under the merger agreement, in the event Exelon or Constellation terminates the merger agreement to accept a superior proposal, or under certain other circumstances, Exelon or Constellation, as applicable, would be required to pay a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon. The acquisition is anticipated to be break-even to Exelon’s adjusted earnings in 2012 and is expected to be accretive to earnings in 2013. The companies anticipate closing the transaction in early 2012.
Acquisition of John Deere Renewables. In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind), a leading operator and developer of wind power, for approximately $893 million in cash. Generation acquired 735 MWs of installed, operating wind capacity located in eight states. Approximately 75% of the operating portfolio’s expected output is already sold under long-term power purchase arrangements. Additionally, Generation will pay up to $40 million related to three projects with a capacity of 230 MWs which are currently in advanced stages of development, contingent upon meeting certain contractual commitments related to the commencement of construction of each project. This contingent consideration was valued at $32 million of which approximately $24 million has been recorded as a current liability and the remainder has been recorded as a noncurrent liability. As a result, total consideration recorded for the Exelon Wind acquisition was $925 million. Generation also has the opportunity to pursue approximately 1,200 MWs of new wind projects that are in various stages of development. The acquisition provides incremental earnings starting in 2012 and cash flows starting in 2013 and is a key part of Exelon 2020.
Proposed Acquisition of Wolf Hollow Generating Station. On May 12, 2011, Generation entered into an agreement to acquire Wolf Hollow, a combined-cycle natural gas-fired power plant in north Texas, for approximately $305 million. Under the terms of the agreement, Generation will acquire 720 MWs of energy within the competitive ERCOT power market. The agreement is contingent upon antitrust clearance and state regulatory approval. The approval process is expected to be completed and the transaction is expected to close during the third quarter of 2011. In connection with the proposed acquisition, Generation’s existing long-term PPA with Wolf Hollow will be terminated upon completion of the transaction. As of June 30, 2011, Generation’s energy purchase commitments related to the Wolf Hollow PPA were approximately $340 million. The proposed acquisition is expected to provide incremental cash flows starting in 2012. Wolf Hollow will not be a “significant subsidiary,” as defined by SEC financial statement reporting requirements, for Exelon or Generation.
Japan Earthquake and Tsunami
On March 11, 2011, Japan experienced a 9.0 magnitude earthquake and ensuing tsunami that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co. These events in Japan increase the risk to Generation that the NRC or other regulatory or legislative bodies may change the laws or regulations covering, among other things, operations, maintenance, license lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological aspects.
Generation believes its nuclear generating facilities do not have the same operating risks as the Fukushima Daiichi plant because they meet the NRC’s requirement that specifies all plants must be able to withstand the most severe natural phenomena historically reported for each plant’s surrounding area, with a significant margin for uncertainty. In addition, Generation’s plants are not located in a significant earthquake zones or in regions where tsunamis are a threat. Generation believes its nuclear generating facilities are able to safely shut down and keep the fuel cooled through multiple redundant systems specifically designed to maintain electric power when electricity is lost from the grid. Further, Generation’s nuclear generating facilities also undergo frequent scenario drills to ensure the proper function of the redundant safety protocols.
During the first half of 2011, the NRC received petitions from various citizen groups requesting actions be taken in response to the events in Japan. First, a consortium of various citizen groups has filed a petition with the NRC to act under its supervisory powers to suspend all reactor licensing decisions and related rulemaking decisions pending the NRC’s investigation of the events at Fukushima Daiichi. Also, a NRC petition was filed seeking suspension of all Boiling Water Reactor (BWR) Mark 1 operating licenses until certain specified conditions are met. This petition could affect Dresden, Quad Cities, Oyster Creek and Peach Bottom stations. Generation has responded to the petitions, and does not believe the petitions will be successful. In addition, on March 21, 2011, the U.S. Court of Appeals for the 3rd Circuit requested that the NRC, Exelon, and the Citizens Group (collectively “the parties”) advise the Court what effect, if any, the damages from the earthquake and tsunami at the Fukushima Daiichi plant may have on the propriety of granting the license renewal application for the Oyster Creek Generating Station. The parties filed responses. On May 18, 2011, the Court of Appeals upheld the NRC’s decision to grant Oyster Creek a 20-year license extension and specifically stated that the events at the Fukushima Daiichi plant do not affect the decision to grant the license extension.
Since the events in Japan took place, Generation has continued to work with regulators and nuclear industry organizations to understand the events in Japan and apply lessons learned. The nuclear industry is already taking specific steps to respond. Generation has completed actions requested by the Institute of Nuclear Power Operations (INPO), which included tests that verified its emergency equipment is available and functional, walk-downs on its procedures related to critical safety equipment, and verification of current qualifications of operators and support staff needed to implement the procedures.
On July 12, 2011, the NRC Near-Term Task Force on the Fukushima Daiichi Accident (Task Force) issued a report of its review of the accident, including recommendations for future regulatory action by the NRC. The report is the first step in a systematic review that the NRC is conducting. The Task Force’s report concluded that nuclear reactors in the United States are operating safely. The report includes recommendations to the NRC in three primary areas: 1) the overall structure and philosophy of the NRC’s regulatory framework; 2) specific design requirements for the nuclear units; and 3) emergency preparedness. Generation is assessing the impacts of the Task Force’s recommendations, both from an operational and a financial impact standpoint. Until the NRC completes its detailed analysis of the recommendations from the Task Force, Generation is unable to determine the impact the recommendations may have on its nuclear units. However, Generation will continue to engage in nuclear industry assessments and actions.
The results of regulatory or political actions associated with the response to the events in Japan and Task Force report could include a substantial increase in Generation’s capital expenditures and operating costs; shortened economic lives for one or more nuclear generating units, resulting in accelerated depreciation charges;
impairment of nuclear generating facilities and/or nuclear fuel inventory; or a change in timing of and/or approach to decommissioning activities, which could increase amounts or accelerate the timing of decommissioning expenditures. In addition, the effect of these changes could cause a downgrade of Exelon and Generation’s credit ratings to below investment grade, resulting in requirements for substantial amounts of collateral and increased borrowing costs for Generation.
The Task Force’s report did not recommend any changes to the existing nuclear licensing process in the United States or changes in the storage of spent nuclear fuel within the plant’s spent nuclear fuel pools. However, as the nuclear situation in Japan remains fluid with ongoing investigations into the nature and extent of damages, the underlying causes of the situation, the degree by which these factors apply to Generation’s nuclear generating facilities and the lack of clarity around regulatory and political responses, Exelon and Generation are unable to predict how the NRC or the nuclear industry will ultimately respond to the events in Japan and whether any response will impact their results of operations, financial positions and cash flows. See the 2010 Form 10-K, Item 1A. Risk Factors, for further discussion of the risk factors.
Generation’s plan for increasing the output through uprates of its nuclear generating stations has not changed as a result of the situation in Japan. However, Generation will continue, as it has in the past, to evaluate each project at the appropriate time and cancel or defer any uprate project that is not considered economical, whether due to energy prices, potential increased regulation, or other factors.
Economic and Market Conditions
Exelon has exposure to various market and financial risks, including the risk of price fluctuations in the wholesale power markets. Wholesale power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular, the prices of natural gas and coal, which drive the wholesale market prices that Generation’s nuclear power plants can command, (2) the rate of expansion of subsidized low carbon generation such as wind energy in the markets in which Generation’s output is sold, (3) the impacts on energy demand of factors such as weather, economic conditions and implementation of energy efficiency and demand response programs, and (4) regulatory and legislative actions, such as the U.S. EPA’s Cross-State Air Pollution Rule (CSAPR) and the New Jersey capacity legislation. SeeEnvironmental Matters andRegulatory and Legislative Matters sections below for further detail on CSAPR and New Jersey capacity legislation, respectively.
The use of new technologies to recover natural gas from shale deposits is expected to increaseincreasing natural gas supply and reserves, which will tend to placeplaces downward pressure on natural gas prices and, could reducetherefore, on wholesale power prices, which results in a reduction in Exelon’s revenues. Additionally, beginning
The market price for electricity is also affected by changes in late 2008, the weak world economy reduced the international demand for coal, oilelectricity. Poorer than expected economic conditions, milder than normal weather and natural gas,the growth of energy efficiency and led to sharply lower fossil fuel pricesdemand response programs can depress demand. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on market prices for electricity prices.and/or capacity. The same economic weaknesscontinued sluggish economy in the United States has also resultedled to a slow down in lowerthe growth of demand for electricity, althoughand ComEd and PECO now project slight increases inare projecting load demand to remain flat in 2010 as2011 compared to load declines experienced in 2009.
Hedging Strategy.Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impactsimpact of market price volatility. Although Exelon’s hedging policies have helped protect Exelon’s earnings as wholesale market prices have declined, sustained increases in natural gas supply and reserve levels, or a continued slow recovery of the economy, could result in a prolonged depression of or further decline in commodity prices and in long-term sluggish loadgrowth in demand.
Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into derivative contracts, including financially-settled swaps, futures contracts and
swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2011 and 2012. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. Generation currently hedges commodity risk on a ratable basis over the three years leading to the spot market. As of June 30, 2011, the percentage of expected generation hedged was 95%-98%, 82%-85%, and 49%-52% for 2011, 2012 and 2013, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well. The expiration of the PPA with PECO at the end of 2010 has resulted in increases in margins earned by Generation in 2011 for the portion of Generation’s electricity portfolio previously sold to PECO under the PPA; however the ultimate impact of entering into new power supply contracts under Generation’s three-year ratable hedging program to replace the PPA will depend on a number of factors, including future wholesale market prices, capacity markets, energy demand and the effects of any new applicable Pennsylvania laws and or rules and regulations promulgated by the PAPUC.
Generation procures coal and natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 56% of Generation’s uranium concentrate requirements from 2011 through 2015 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position. Generation uses long-term contracts and financial instruments such as over-the-counter and exchange-traded instruments to mitigate price risk associated with certain commodity price exposures. Both ComEd and PECO mitigate exposure as a result of the regulatory mechanisms that allow them to recover procurement costs from retail customers.
New Growth Opportunities
Nuclear Uprate Program. During 2009, Generation announced a series of planned power uprates across its nuclear fleet that willwould result in between 1,300 and 1,500 MWMWs of additional generation capacity within eight years. The uprate projects representyears at a total investment of approximately $3.5$3.65 billion in overnight cost, as measured in current costs.2010 dollars. Overnight costs do not include financing costs or cost escalation. As part of periodic reviews of the continued economic viability of the projects, the planned increases have been revised to between 1,175 and 1,300 MWs at an overnight cost of approximately $3.30 billion in 2011 dollars primarily due to the deletion of the Three Mile Island extended power uprate from the plan due to low economic evaluation results. Using proven technologies, the projects take advantage of new production and measurement technologies, new materials and learning from a half-century of nuclear power operations. Uprate projects, representing approximately one half70% of the planned uprates,uprate MWs, are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Byron, Braidwood, Dresden, LaSalle and Quad Cities plants in Illinois. The remainderremaining uprate MWs will come from additional projects across Generation’s nuclear fleet beginning later in the second half of 20102011 and ending in 2017. At 1,5001,300 nuclear-generated MW,MWs, the uprates would displace 86 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates are being undertaken pursuant to an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the project in light of changing market conditions. The amount of expenditures to implement the
plan ultimately will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.
The ability to implement several projects requires the successful resolution of various technical issues. The resolution of these issues may affect the timing and amount of the power increases associated with the power uprate initiative. Through June 30, 2011, Generation has added 194 MWs of nuclear generation through its uprate program, with another 11 MWs scheduled to be added during the remainder of 2011.
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On April 15, 2011, the PAPUC issued the order approving the joint petition for partial settlement of the initial dynamic pricing and customer acceptance plan and ruled that the administrative costs be recovered from default service customers through the GSA. PECO plans to file for approval of a universal meter deployment plan for its remaining customers in 2012.
In October 2009, the ICC approved ComEd’s proposed AMI pilot program, with minor modifications, and recovery of substantially all program costs from customers. The one-year program was fully implementedoperational in June 2010. The total anticipated costAs of June 30, 2011, ComEd had spent $77 million associated with the pilot program is approximately $69 million.program. The AMI pilot program allows ComEd to study the costs and benefits related to automated metering and to develop the cost estimate of potential full system-wide implementation of AMI. In addition, the program allows customers the ability to manage energy use, improve energy efficiency and potentially lower energy bills.
Liquidity and Cost Management
Pension Plan Funding. As a result of accelerated cash benefits associated with the Tax Relief Act of 2010, Exelon iscontributed $2.1 billion to its pension plans in January 2011, representing all currently planned 2011 qualified pension contributions. Exelon’s funding of these contributions included $500 million from cash from operations, $750 million from the tax benefits of making the pension contributions and $850 million associated with the accelerated cash tax benefits from the 100% bonus depreciation provision enacted as part of the Tax Relief Act of 2010. Exelon expects the $2.1 billion contribution, along with other factors, will increase the pension funded status from 71% at December 31, 2010 to 89% at December 31, 2011, subject to significant ongoing cost pressures during these challenging economic times. actual 2011 asset returns and final actuarial valuations. The $2.1 billion pension contribution also decreased 2011 pension costs.
Financing Activities. On January 18, 2011, ComEd issued $600 million of 1.625% First Mortgage Bonds due January 15, 2014. The net proceeds of the bonds were used as an interim source of liquidity for the January 2011 contribution to Exelon-sponsored pension plans in which ComEd participates. ComEd anticipates receiving tax refunds as a result of both the pension contribution and the Tax Relief Act of 2010 allowing for 100% bonus depreciation deductions in 2011 and 2012. As a result, the immediate use of the net proceeds to fund the planned contribution will allow those future cash receipts to be available to fund capital investment and for general corporate purposes.
Credit Facilities. On March 23, 2011, Exelon Corporate, Generation and PECO replaced their unsecured revolving credit facilities with new facilities with aggregate bank commitments of $500 million, $5.3 billion and $600 million, respectively. Although the covenants are largely the same as the prior facilities, the new facilities have higher borrowing costs, reflecting current market pricing. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information regarding those costs.
ComEd’s $1.0 billion unsecured revolving credit facility expires on March 25, 2013 unless extended in accordance with terms. ComEd plans to renew or replace the credit facility in 2012. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information regarding the credit facility terms.
Generation’s, ComEd’s and PECO’s credit facility agreements of $30 million, $32 million and $32 million, respectively, with minority and community banks expire on October 21, 2011. Generation, ComEd and PECO plan to replace the credit facilities at that time. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information regarding the credit facilities.
Cost Management. Exelon is committed to operating its businesses responsibly and managing its operating and capital costs in a manner that serves its customers and produces value for its shareholders. Exelon is also committed to an ongoing strategy to make itself more effective, efficient and innovative. In 2009, Exelon launched a company-wide cost management initiative, which combines short-term actions with long-term change. In the short-term, Exelon realized cost savings, primarily as a result of the elimination of 500 positions within BSC and ComEd in 2009, productivity improvements and stringent controls on supply spending, contracting and overtime costs. Exelon is committed to maintaining a cost control focus and expectscontinues to largely offset increasing pension and benefits expense and general inflation in 2010 with additionalanalyze cost savings, including freezing executive salaries and reducing employee benefits. With regard to long-term changes, Exelon is analyzing cost trends over the past five years to identify future cost savings opportunities and implementingimplement more planning and performance-measurement tools thatto allow it to better identify areas for sustainable productivity improvements and cost reductions across the Registrants.
Environmental Matters
Exelon 2020. In 2008, Exelon announced a comprehensive business and environmental strategic plan, which details an enterprise-wide strategy and a wide range of initiatives being pursued by Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020 (from 2001 levels). Exelon has incorporated Exelon 2020 into its $952 million credit facility with a similar $1 billion unsecured revolving credit facility that extendsoverall business plans, and as further legislation and regulation imposing requirements on emissions of air pollutants are promulgated, its emissions reduction efforts will position Exelon to March 25, 2013. Althoughbenefit from the covenants are largely the same as the prior facility, the new facility has higher borrowing costs, reflecting current market pricing. See Note 5long-term positive impact of the Combined Notes to Consolidated Financial Statements for further information regarding those costs. Exelon’s, Generation’s,requirements on capacity and PECO’s credit facilities largely extend through October 2012. These credit facilities currently provide sufficient liquidity to eachenergy prices while minimizing the impact of the Registrants. Upon maturity of these credit facilities, Exelon, Generation and PECO may not be able to renew or replace these existing facilities at current terms or commitment levels from banks. Consequently, Exelon, Generation, and PECO may face increased costs for liquidity needs in 2011 and may choose to establish alternative liquidity sources as appropriate.
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Environmental Legislative and Regulatory Developments
Exelon supports the last rate filing in 2007. The requested increase also reflects increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The requested ratepromulgation of return on common equity is 11.5%. The requested increase in electric distribution rates would increase the average residential customer’s monthly electric billenvironmental regulation by approximately 7%. In addition, ComEd is requesting future recovery of certain amounts that were previously recorded as expense. If that request is approved, ComEd would reverse the previously expensed costs and establish regulatory assets with amortization over the period during which rate recovery is allowed. As a result, ComEd would recognize a one-time benefit of up to $39 million (pre-tax) to reverse the prior charges. The requested increase also includes $22 million for increased uncollectible accounts expense. If the rate request is approved, the threshold for determining over/under recoveries under ComEd’s uncollectible accounts tariff would be increased by $22 million. The new electric distribution rates would take effect no later than June 2011. ComEd cannot predict how much of the requested electric distribution rate increase the ICC may approve.
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Air.Beginning with the CATR,CSAPR, the air requirements are expected to be implemented through a series of increasingly stringent regulations relating to conventional air pollutants (e.g., NOx, SO2 and particulate matter) as well as HAPs (e.g., acid gases, mercury and other heavy metals). UnderThe U.S. EPA has announced that it will complete a review of NAAQS in the proposal, the first phase of the NOx2011 — 2012 timeframe for ozone (nitrogen oxide and SO2 emissions reductions under the CATR would commencevolatile organic chemicals), particulate matter, nitrogen dioxide, sulfur dioxide, and lead. This review will likely result in 2012, with further reductions of SO2 emissions proposed to become effective in 2014. Establishedmore stringent emissions limits will be further reduced ason fossil-fired electric generating stations. There is opposition among fossil-fuel fired generation owners to the potential stringency and timing of these air regulations, and the House Commerce and Energy Committee has held a number of hearings on these issues.
On July 7, 2011, the U.S. EPA finalizes more restrictive NAAQS forpublished a final rule known as CSAPR. The CSAPR requires 27 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particulate matterparticle pollution in other states. Upon preliminary review, it is expected that implementation of the 2010 —CSPAR will modestly increase power prices over the long term, which would result in a net benefit to Generation’s results of operations and cash flows.
On March 16, 2011, timeframe. Finally, the most restrictive requirements will be imposed by finalization of a new HAP standard for electric generating units, which the U.S. EPA issued a proposed rule setting national emission standards for HAPs from coal- and oil-fired electric generating facilities (the Toxics Rule). The Toxics Rule would require coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is requiredexpected that owners of smaller, older, uncontrolled coal units will retire the units rather than make these investments. Coal units with existing controls that do not meet the Toxics Rule may need to complete by November 2011 pursuantupgrade existing controls or add new controls to a Consent Decree settling litigation undercomply. Exelon, along with the former CAMR. The HAP standard is technology based andother co-owners of Conemaugh Generating Station, are evaluating controls needed to comply with the Toxics Rule. EPA’s proposed standards will require oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the installationproposed emission standards may choose to convert the units to light oils or natural gas, install control technologies, or retire the units. The ultimate nature and extent of future required regulatory controls on HAP emissions at electric generation power plants will not be determined until the maximum achievable control technology (MACT)Toxics Rule is finalized by the EPA in November 2014. 2011.
The cumulative impact of these regulations could be to require power plant operators to expend significant capital to install pollution control technologies, including wet flue gas desulfurization technology for SO2 and acid gases, and selective catalytic reduction technology for NOx.
In the absence of Federal legislation, the U.S. EPA is also moving forward with the regulation of GHG emissions under the Clean Air Act, including permitting requirements under the PSD and Title V operating permit sections of the Clean Air Act for new and modified stationary sources that became effective on January 2, 2011, and proposed GHG emissions limitations under the CATR establishes an aggressive, streamlined processNew Source Performance Standards scheduled for finalization in May 2012 pursuant to a litigation settlement.
Exelon supports comprehensive climate change legislation by the U.S Congress, including a mandatory, economy-wide cap-and-trade program for GHG emissions that could resultbalances the need to protect consumers, business
and the economy with the urgent need to reduce national GHG emissions. Several bills containing provisions for legislation of GHG emissions were introduced in Congress during the 111th Congress, but none were passed by both houses of Congress.
Water. Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. Regulations adopted by the U.S. EPA in 2004 applicable to large electric generating stations were withdrawn in 2007 following a decision by the U.S. Second Circuit Court of Appeals that invalidated many of the rule’s significant capital expendituresprovisions and remanded the rule to the EPA for NOxfurther consideration and SO2 pollution control equipment for plant operators as early as 2014 - -2015. Given its low carbon generation portfolio, Exelonrevision. On March 28, 2011, the EPA issued a proposed rule, and is required under a Settlement Agreement to issue a final rule by July 27, 2012. The proposed rule does not currently expectrequire closed cycle cooling (e.g., cooling towers) as the adoption of the rules as proposed to have a significant impact on its future capital spending requirements.
It is unknown at this time whether the final regulations or permit will require closed-cycle cooling at Salem. In addition, the economic viability of Generation’s other power generation facilities without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and restrict entirelyretain the use of pre-2012 allowances. Existing SO2 allowances underflexibility afforded the Title IV Acid Rain Program (ARP) would remain available for use under that Program. Exelon is evaluatingstate permitting agencies in applying a cost — benefit test and to consider site-specific factors, the impact the proposed CATR regulations may have on the market value of its ARP SO2 allowances and its net investment in long-term direct financing leases of coal-fired plants in Georgia and Texas. See Note 12 of the Combined Notesrule would be minimized even though the costs of compliance could be material to Consolidated Financial Statements for further detail related to the possible impact on Exelon’s results of operations and financial position.
Waste.Under proposed U.S. EPA rules issued on June 21, 2010, coal combustion waste (CCW) would be regulated for the first time under the Federal Resource Conservation and Recovery Act.RCRA. The U.S. EPA is considering several options, including classification of CCW either as a hazardous or non-hazardous waste. Under either option, the U.S. EPA’s intention is the ultimate elimination of surface impoundments as a waste treatment process. For impacted plants affected by the proposed rules, this would result in significant capital expenditures and variable operating and maintenance expenditures to convert to dry handling and disposal systems and installation of new waste water treatment facilities. Generation anticipates that the only plants in which it has an ownership interest that would be affected by proposed rules would be Keystone and Conemaugh. As a result, Exelon does not currently expect the adoption of the rules as proposed to have a significant impact on its future capital spending requirements and operating costs.
CCW rules.
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Health Care Reform LegislationRegulatory and Legislative Matters
Appeal of 2007 Illinois Electric Distribution Rate Case. On September 30, 2010, the Health Care Reform Acts were signed into law. A number of provisionsIllinois Appellate Court (Court) issued a decision in the Health Care Reform Acts impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costsappeals related to the extentICC’s order in ComEd’s 2007 electric distribution rate case (2007 Rate Case). That decision ruled against ComEd on the treatment of post-test year accumulated depreciation and the recovery of costs for an employer’s postretirement health care plan receives Federal subsidiesAMI/Customer Applications pilot program via a rider (Rider SMP). On January 25, 2011, ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court that provide retiree prescription drug benefits at least equivalentwas denied on March 30 2011. The matter has been returned to Medicare prescription drug benefits. Although this changethe ICC. ComEd expects that the ICC will issue a final order with respect to the aforementioned issues before the end of 2011. ComEd recorded an estimated refund obligation of $55 million and $22 million related to the post-test year accumulated depreciation and AMI/Customer Applications pilot program issues as of June 30, 2011 and December 31, 2010, respectively. ComEd does not take effect immediately,believe any of its other riders are affected by the Registrants are requiredCourt’s ruling. See Note 3 of the Combined Notes to recognizeConsolidated Financial Statements for further details related to the full accounting impactCourt’s order.
2010 Illinois Electric Distribution Rate Case. On May 24, 2011, the ICC issued an order in their financial statementsComEd’s 2010 electric delivery services rate case. ComEd requested an increase in the periodannual revenue requirement to
allow ComEd to recover the costs of substantial investments made in its distribution system since its last rate filing in 2007. The requested increase also reflected increased costs, most notably pension and other postretirement employee benefits, since ComEd’s rates were last determined.
The ICC order, which became effective on June 1, 2011, approved a $143 million increase to ComEd’s annual delivery services revenue requirement, which is approximately 42% of the legislation was enacted.$343 million requested by ComEd in its reply brief on February 23, 2011. The approved rate of return on common equity is 10.50%. As a result inof the first quarter of 2010, Exelonorder, ComEd recorded total after-tax chargesa one-time net benefit of approximately $65$58 million that includes the reestablishment of previously expensed plant balances, the establishment of new regulatory assets, and the reversal of certain reserves. The benefit is reflected as an increase to operating revenues and a reduction in operating and maintenance expense and income tax expense for the three and six months ended June 30, 2011. The order has been appealed to reverse deferred tax assets previously established. Of this total, Generation,the Court by several parties, including ComEd. ComEd cannot predict the results of these appeals. See Note 3 of the Combined Notes to Consolidated Financial Statements for further details related to the 2010 Rate Case.
Legislation to Modernize Electric Utility Infrastructure and to Update Illinois Ratemaking Process. ComEd and PECO recorded chargesAmeren are working with state legislators to enact legislation that would modernize Illinois’ electric grid. The legislation includes a policy-based approach that would provide a more predictable ratemaking system and would enable utilities to modernize the electric grid and set the stage for fostering economic development while creating and retaining jobs. Many other states are changing or are considering changes to the way they regulate utilities in order to improve the predictability of $24 million, $11 millionthe ratemaking process.
The Illinois Energy Infrastructure Modernization Act (SB 1652), a prior version of which was originally introduced as HB 14, was passed by the Illinois General Assembly on May 31, 2011. SB 1652 would apply to electric utilities in Illinois on an opt-in basis. SB 1652 provides greater certainty related to the recovery of costs by a utility through a pre-established formula, which would still allow the ICC and $9 million, respectively. The reductioninterveners the opportunity to review the prudence and reasonableness of these income tax deductions iscosts. If the legislation were to be enacted, ComEd would anticipate filing annual electric distribution formula rate cases and investing an additional $2.6 billion in capital expenditures over the next ten years to modernize its system and implement smart grid technology, including improvements to cyber security. These investments would be incremental to ComEd’s historical level of capital expenditures. SB 1652 also estimated to increase Exelon’s total annual income tax expense by approximately $10 million to $15 million. Of this total, Generation’s, ComEd’s and PECO’s annual income tax expense is estimated to increase $5 million to $8 million, $3 million to $4 million and $1 million to $2 million, respectively.
The bill remains in the Illinois Senate on a motion filed by the President of the Senate. When it is ultimately presented to the Governor, he has sixty days to decide on the bill; however, he has indicated that imposes an excise taxhe may veto it. If approved in its current form, ComEd expects that it would begin to achieve closer to its allowed return on certain high-cost plansequity, which would have a material positive impact on ComEd’s net income as early as 2011. ComEd’s commitments in the bill associated with incremental capital expenditures would result in significant cash outflows beginning in 2018, whereby premiums paid over2012. ComEd cannot predict the eventual outcome of SB 1652 resulting from the Governor’s decision or subsequent actions taken by the Illinois General Assembly. To the extent that the bill is not enacted as currently written or in a prescribed thresholdcomparable form, ComEd will be taxed at a 40% rate. Exelon does not currently believeseek alternative methods to achieve reasonable earned returns on equity, which would include additional electric distribution rate case filings with the excise tax or other provisionsICC.
2011 Pennsylvania Electric and Natural Gas Rates. On December 16, 2010, the PAPUC approved the settlement of PECO’s electric distribution rate case for an increase of $225 million in annual service revenue, which is approximately 71% of the Health Care Reform Acts will materially$316 million originally requested. The natural gas distribution rate case settlement reflects an increase its postretirement benefit obligation. Accordingly, a re-measurement of Exelon’s postretirement benefit obligationapproximately $20 million in annual service revenue, which is not required at this time. However, Exelon will continue to monitor and assess the impactapproximately 46% of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented,$44 million originally requested. The approved electric and natural gas distribution rates became effective on its future results of operations, cash flows or financial position. Exelon will reflect its best estimateJanuary 1, 2011.
See Note 3 of the expected impacts in its annual actuarial measurement at December 31, 2010, which could result in increased postretirement benefit costs in future years. Exelon may consider plan structure changes in future periodsCombined Notes to respondConsolidated Financial Statements for further details related to the provisions of the Health Care Reform Acts and optimally manage its employee benefit costs, subject to collective bargaining agreements, where applicable.
PECO’s rate case settlements.
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New Jersey Capacity Legislation. New Jersey Senate Bill 2381 was enacted into law on January 28, 2011. This legislation established a long-term capacity pilot program under which the New Jersey Board of Public Utilities (NJBPU) administered an RFP process in the first quarter of 2011 to solicit offers for capacity agreements with mid-merit and/or base-load generation constructed after the effective date of the bill. In the first quarter of 2011, the NJBPU approved the RFP results, which included capacity agreements for a term of up to 15 years for 2,000 MWs. The NJBPU has initiated a proceeding to examine whether additional capacity is needed. A final staff report is due to be issued before the end of the year.
The selected generators from the RFP process are required to bid in and clear the PJM RPM auction, likely causing them to bid in the PJM RPM auction at zero. Under the pilot program, generators are paid based on the RFP contract price; therefore, any difference between the RPM clearing price and the RFP contract price is either ultimately recovered from or refunded to New Jersey electric customers. This state-required customer subsidy for generation capacity is expected to artificially suppress capacity prices within the Mid-Atlantic region in future auctions, which could adversely affect Generation’s results of operations and cash flows. Other states could seek to establish similar programs, which could substantially impair Exelon’s market driven position.
PJM’s capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. See Note 3 of the Combined Notes to Consolidated Financial Statements for further details related to PJM’s MOPR.
Tax Matters
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction. During 2008, Generation uses long-term contractsbenefited from a provision in the Energy Policy Act of 2005 which allowed companies an income tax deduction for a “special transfer” of funds from a non-tax qualified NDT fund to a qualified NDT fund. As a result of
temporary guidance published by the U.S. Department of Treasury, Generation completed a special transfer in the first quarter of 2008 for tax year 2008. In December 2010, the U.S. Department of Treasury issued final regulations under IRC Section 468A. The final regulations included a transitional relief provision which allowed taxpayers to request permission from the IRS to designate a taxable year, as far back as 2006, during which the special transfer will be deemed to have occurred. Exelon determined, and financial instruments suchis confirming with the IRS through the ruling process, that this provision allows a majority of Generation’s 2008 special transfer tax deduction to be claimed in the 2006 tax year and the remaining portions claimed ratably in taxable years 2007 and 2008. On February 18, 2011, in order to preserve both the ability to designate the special transfer from 2008 to an earlier taxable year and the ability to complete future additional special transfers, Exelon filed ruling requests with the IRS. Exelon has received its first favorable ruling from the IRS in the second quarter of 2011, along with several additional favorable rulings during July 2011, and expects that the remaining rulings to be received will be favorable as over-the-counterwell. As a result, Exelon recorded an interest and exchange-traded instrumentstax benefit of $43 million, net of tax including the impact on the manufacturer’s deduction, in the second quarter of 2011 related to mitigate price risk associated with certain commodity price exposures.
the special transfer completed in 2008. If additional special transfers are made, Exelon is estimating that it will record an additional interest benefit of up to $6 million (after-tax) in the second half of 2011.
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Plant Retirements
Eddystone and Cromby. In 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit effective May 31, 2011 in response to the economic outlook related to the continued operation of these four units. However, PJM determined that transmission reliability upgrades would be necessary to alleviate reliability impacts and that those upgrades would be completed in a manner that would permit Generation’s retirement of two of the units on that date and two of the units subsequent to May 31, 2011. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired; however, Cromby Unit 2 will retire on
December 31, 2011 and Eddystone Unit 2 on June 1, 2012. On May 27, 2011, the FERC approved a settlement providing for a reliability-must-run rate schedule, which defines compensation to be paid to Generation for continuing to operate these units. The monthly fixed-cost recovery during the reliability-must-run period for Eddystone Unit 2 and Cromby Unit 2 is approximately $6 million and $2 million, respectively. In addition, Generation is recovering variable costs including fuel, emissions costs, chemicals, auxiliary power and for project investment costs during the reliability-must-run period. Eddystone Unit 2 and Cromby Unit 2 began operating under the reliability-must-run agreement effective June 1, 2011.
Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in Exelon’s 20092010 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, purchase accounting, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies and revenue recognition. At June 30, 2010,2011, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2009.
New Accounting Pronouncements
Net Income (Loss) by Registrant
Three Months Ended | Favorable | Six Months Ended | Favorable | |||||||||||||||||||||
June 30, | (Unfavorable) | June 30, | (Unfavorable) | |||||||||||||||||||||
2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
Generation | $ | 382 | $ | 512 | $ | (130 | ) | $ | 943 | $ | 1,041 | $ | (98 | ) | ||||||||||
ComEd | 9 | 116 | (107 | ) | 125 | 230 | (105 | ) | ||||||||||||||||
PECO | 75 | 71 | 4 | 176 | 183 | (7 | ) | |||||||||||||||||
Other (a) | (21 | ) | (42 | ) | 21 | (50 | ) | (85 | ) | 35 | ||||||||||||||
Exelon | $ | 445 | $ | 657 | $ | (212 | ) | $ | 1,194 | $ | 1,369 | $ | (175 | ) | ||||||||||
Three Months Ended June 30, | Favorable (Unfavorable) Variance | Six Months Ended June 30, | Favorable (Unfavorable) Variance | |||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||
Generation | $ | 443 | $ | 382 | $ | 61 | $ | 938 | $ | 943 | $ | (5 | ) | |||||||||||
ComEd | 114 | 9 | 105 | 183 | 125 | 58 | ||||||||||||||||||
PECO | 83 | 75 | 8 | 210 | 176 | 34 | ||||||||||||||||||
Other(a) | (20 | ) | (21 | ) | 1 | (43 | ) | (50 | ) | 7 | ||||||||||||||
Exelon | $ | 620 | $ | 445 | $ | 175 | $ | 1,288 | $ | 1,194 | $ | 94 | ||||||||||||
(a) | Other primarily includes |
Results of Operations — Generation
Three Months Ended | Favorable | Six Months Ended | Favorable | |||||||||||||||||||||
June 30, | (Unfavorable) | June 30, | (Unfavorable) | |||||||||||||||||||||
2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
Operating revenues | $ | 2,353 | $ | 2,378 | $ | (25 | ) | $ | 4,773 | $ | 4,979 | $ | (206 | ) | ||||||||||
Purchased power and fuel expense | 899 | 891 | (8 | ) | 1,497 | 1,575 | 78 | |||||||||||||||||
Revenue net of purchased power and fuel expense (a) | 1,454 | 1,487 | (33 | ) | 3,276 | 3,404 | (128 | ) | ||||||||||||||||
Other operating expenses | ||||||||||||||||||||||||
Operating and maintenance | 691 | 689 | (2 | ) | 1,432 | 1,617 | 185 | |||||||||||||||||
Depreciation and amortization | 115 | 72 | (43 | ) | 223 | 149 | (74 | ) | ||||||||||||||||
Taxes other than income | 61 | 50 | (11 | ) | 118 | 100 | (18 | ) | ||||||||||||||||
Total other operating expenses | 867 | 811 | (56 | ) | 1,773 | 1,866 | 93 | |||||||||||||||||
Operating income | 587 | 676 | (89 | ) | 1,503 | 1,538 | (35 | ) | ||||||||||||||||
Three Months Ended June 30, | Favorable (Unfavorable) Variance | Six Months Ended June 30, | Favorable (Unfavorable) Variance | |||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||
Operating revenues | $ | 2,546 | $ | 2,353 | $ | 193 | $ | 5,285 | $ | 4,773 | $ | 512 | ||||||||||||
Purchased power and fuel expense | 932 | 899 | (33 | ) | 1,911 | 1,497 | (414 | ) | ||||||||||||||||
Revenue net of purchased power and fuel expense(a) | 1,614 | 1,454 | 160 | 3,374 | 3,276 | 98 | ||||||||||||||||||
Other operating expenses | ||||||||||||||||||||||||
Operating and maintenance | 763 | 691 | (72 | ) | 1,517 | 1,432 | (85 | ) | ||||||||||||||||
Depreciation and amortization | 138 | 115 | (23 | ) | 277 | 223 | (54 | ) | ||||||||||||||||
Taxes other than income | 66 | 61 | (5 | ) | 132 | 118 | (14 | ) | ||||||||||||||||
Total other operating expenses | 967 | 867 | (100 | ) | 1,926 | 1,773 | (153 | ) | ||||||||||||||||
Operating income | 647 | 587 | 60 | 1,448 | 1,503 | (55 | ) | |||||||||||||||||
Other income and deductions | ||||||||||||||||||||||||
Interest expense | (45 | ) | (37 | ) | (8 | ) | (91 | ) | (72 | ) | (19 | ) | ||||||||||||
Other, net | 76 | (133 | ) | 209 | 152 | (54 | ) | 206 | ||||||||||||||||
Total other income and deductions | 31 | (170 | ) | 201 | 61 | (126 | ) | 187 | ||||||||||||||||
Income before income taxes | 678 | 417 | 261 | 1,509 | 1,377 | 132 | ||||||||||||||||||
Income taxes | 235 | 35 | (200 | ) | 571 | 434 | (137 | ) | ||||||||||||||||
Net income | $ | 443 | $ | 382 | $ | 61 | $ | 938 | $ | 943 | $ | (5 | ) | |||||||||||
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Three Months Ended | Favorable | Six Months Ended | Favorable | |||||||||||||||||||||
June 30, | (Unfavorable) | June 30, | (Unfavorable) | |||||||||||||||||||||
2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
Other income and deductions | ||||||||||||||||||||||||
Interest expense | (37 | ) | (24 | ) | (13 | ) | (72 | ) | (52 | ) | (20 | ) | ||||||||||||
Equity in losses of investments | — | — | — | — | (1 | ) | 1 | |||||||||||||||||
Other, net | (133 | ) | 215 | (348 | ) | (54 | ) | 133 | (187 | ) | ||||||||||||||
Total other income and deductions | (170 | ) | 191 | (361 | ) | (126 | ) | 80 | (206 | ) | ||||||||||||||
Income before income taxes | 417 | 867 | (450 | ) | 1,377 | 1,618 | (241 | ) | ||||||||||||||||
Income taxes | 35 | 355 | 320 | 434 | 577 | 143 | ||||||||||||||||||
Net income | $ | 382 | $ | 512 | $ | (130 | ) | $ | 943 | $ | 1,041 | $ | (98 | ) | ||||||||||
(a) | Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
Net Income
Three Months Ended June 30, 20102011 Compared to Three Months Ended June 30, 20092010. Generation’s net income decreasedincreased compared to the same period in 2010 primarily due to unfavorablehigher revenues resulting from the expiration of the PECO PPA on December 31, 2010, favorable portfolio and market conditions in the South and West region, more favorable NDT fund performance and lower operating revenues, netthe impacts of purchased powera one-time interest and fuel expense;tax benefit from the NDT fund special transfer tax deduction. These favorable impacts were partially offset by lower costs associated with the Illinois Settlement Legislation. Lowerhigher operating revenues, net of purchased power and fuelmaintenance expense, were largelyprimarily due to unfavorable portfolio and market conditions, partially offset by decreased mark-to-market losses on economic hedging activities.
Six Months Ended June 30, 20102011 Compared to Six Months Ended June 30, 2009.2010.Generation’s net income decreased compared to the same period in 2010 primarily due to unfavorable NDT fund performancemark-to-market losses on economic hedging activities, higher depreciation and lower operating revenues, net of purchased power and fuel expense; partially offset by lower operating and maintenance expense and lower costs associated with the Illinois Settlement Legislation. Lower operatingimpact of higher nuclear fuel prices. These unfavorable impacts were partially offset by higher revenues net of purchased power and fuel expense, were largely due to unfavorablethe expiration of the PECO PPA on December 31, 2010, favorable portfolio and market conditions in the South and decreased nuclear output as a result ofWest region, more planned refueling outage days in 2010; partially offset by increased mark-to-market gains on economic hedgingfavorable NDT fund performance and proprietary trading activities. Lower operating and maintenance expense primarily reflected the impacts of a one-time interest and tax benefit from the impairment of certain generating assets in 2009, partially offset by increased nuclear refueling outage costs associated with the higher number of refueling outage days in 2010.
Revenue Net of Purchased Power and Fuel Expense
Generation primarily operates inhas three segments:reportable segments, the Mid-Atlantic, Midwest, and South and West regions representing the different geographical areas in which Generation’s power marketing activities are conducted.
Mid-Atlantic includes Generation’s operations primarily in Pennsylvania, New Jersey and Maryland; the Midwest includingincludes the operations in Illinois, Indiana, Michigan and Indiana;Minnesota; and the South where the most significantand West includes operations are locatedprimarily in Texas, Georgia, Oklahoma, Kansas, Missouri, Idaho and Oklahoma.
Generation evaluates the operating performance of its power marketing activities using the measure of revenue net of purchased power and fuel expense. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd and PECO. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and fuel costs associated with tolling agreements.ancillary services. Fuel expense includes the fuel costs for internally generated energy.energy and fuel costs associated with tolling agreements. Generation’s retail gas, proprietary trading, compensation under the reliability-must-run rate schedule, other revenuerevenues and mark-to-market activities are not allocated to a region.
105
Three Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
2010 | 2009 | Variance | % Change | |||||||||||||
Mid-Atlantic (a) (b) | $ | 583 | $ | 682 | $ | (99 | ) | -14.5 | % | |||||||
Midwest (b) | 1,016 | 1,017 | (1 | ) | -0.1 | % | ||||||||||
South | (43 | ) | (25 | ) | (18 | ) | -72.0 | % | ||||||||
Total electric revenue net of purchased power and fuel expense | $ | 1,556 | $ | 1,674 | $ | (118 | ) | -7.0 | % | |||||||
Trading portfolio | 19 | 3 | 16 | 533.3 | % | |||||||||||
Mark-to-market losses | (124 | ) | (173 | ) | 49 | 28.3 | % | |||||||||
Other (c) | 3 | (17 | ) | 20 | 117.6 | % | ||||||||||
Total revenue net of purchased power and fuel expense | $ | 1,454 | $ | 1,487 | $ | (33 | ) | -2.2 | % | |||||||
Six Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
2010 | 2009 | Variance | % Change | |||||||||||||
Mid-Atlantic (a) (b) | $ | 1,197 | $ | 1,377 | $ | (180 | ) | -13.1 | % | |||||||
Midwest (b) | 2,010 | 2,090 | (80 | ) | -3.8 | % | ||||||||||
South | (91 | ) | (58 | ) | (33 | ) | -56.9 | % | ||||||||
Total electric revenue net of purchased power and fuel expense | $ | 3,116 | $ | 3,409 | $ | (293 | ) | -8.6 | % | |||||||
Trading portfolio | 25 | 3 | 22 | 733.3 | % | |||||||||||
Mark-to-market gains | 109 | 12 | 97 | 808.3 | % | |||||||||||
Other (c) | 26 | (20 | ) | 46 | 230.0 | % | ||||||||||
Total revenue net of purchased power and fuel expense | $ | 3,276 | $ | 3,404 | $ | (128 | ) | -3.8 | % | |||||||
Three Months Ended June 30, | Variance | % Change | ||||||||||||||
2011 | 2010 | |||||||||||||||
Mid-Atlantic(a)(b) | $ | 821 | $ | 583 | $ | 238 | 40.8 | % | ||||||||
Midwest(b) | 887 | 1,016 | (129 | ) | (12.7 | %) | ||||||||||
South and West | (11 | ) | (43 | ) | 32 | 74.4 | % | |||||||||
|
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|
|
| |||||||||
Total electric revenue net of purchased power and fuel expense | $ | 1,697 | $ | 1,556 | $ | 141 | 9.1 | % | ||||||||
Trading portfolio | 16 | 19 | (3 | ) | (15.8 | %) | ||||||||||
Mark-to-market losses | (124 | ) | (124 | ) | — | n.m. | ||||||||||
Other(c) | 25 | 3 | 22 | n.m. | ||||||||||||
|
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|
|
|
|
|
| |||||||||
Total revenue net of purchased power and fuel expense | $ | 1,614 | $ | 1,454 | $ | 160 | 11.0 | % | ||||||||
|
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|
|
|
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|
Six Months Ended June 30, | Variance | % Change | ||||||||||||||
2011 | 2010 | |||||||||||||||
Mid-Atlantic(a)(b) | $ | 1,737 | $ | 1,197 | $ | 540 | 45.1 | % | ||||||||
Midwest(b) | 1,851 | 2,010 | (159 | ) | (7.9 | %) | ||||||||||
South and West | (14 | ) | (91 | ) | 77 | 84.6 | % | |||||||||
|
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|
|
|
|
|
| |||||||||
Total electric revenue net of purchased power and fuel expense | $ | 3,574 | $ | 3,116 | $ | 458 | 14.7 | % | ||||||||
Trading portfolio | 22 | 25 | (3 | ) | (12.0 | %) | ||||||||||
Mark-to-market gains (losses) | (272 | ) | 109 | (381 | ) | n.m. | ||||||||||
Other(c) | 50 | 26 | 24 | n.m. | ||||||||||||
|
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|
|
| |||||||||
Total revenue net of purchased power and fuel expense | $ | 3,374 | $ | 3,276 | $ | 98 | 3.0 | % | ||||||||
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(a) | Included in the Mid-Atlantic region are the results of generation in New England. | |
(b) | Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively. | |
(c) | Includes retail gas activities and other |
Generation’s supply sources by region are summarized below:
Three Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
Supply source (GWh) | 2010 | 2009 | Variance | % Change | ||||||||||||
Nuclear generation | ||||||||||||||||
Mid-Atlantic (a) | 11,691 | 12,276 | (585 | ) | -4.8 | % | ||||||||||
Midwest | 23,344 | 22,719 | 625 | 2.8 | % | |||||||||||
Fossil and hydro generation | ||||||||||||||||
Mid-Atlantic (b) | 2,175 | 2,279 | (104 | ) | -4.6 | % | ||||||||||
Midwest | 7 | 3 | 4 | 133.3 | % | |||||||||||
South | 310 | 419 | (109 | ) | -26.0 | % | ||||||||||
Purchased power (c) | ||||||||||||||||
Mid-Atlantic | 414 | 372 | 42 | 11.3 | % | |||||||||||
Midwest | 1,568 | 1,673 | (105 | ) | -6.3 | % | ||||||||||
South | 2,695 | 3,231 | (536 | ) | -16.6 | % | ||||||||||
Total supply by region | ||||||||||||||||
Mid-Atlantic | 14,280 | 14,927 | (647 | ) | -4.3 | % | ||||||||||
Midwest | 24,919 | 24,395 | 524 | 2.1 | % | |||||||||||
South | 3,005 | 3,650 | (645 | ) | -17.7 | % | ||||||||||
Total supply | 42,204 | 42,972 | (768 | ) | -1.8 | % | ||||||||||
Three Months Ended June 30, | Variance | % Change | ||||||||||||||
Supply source (GWh) | 2011 | 2010 | ||||||||||||||
Nuclear generation(a) | ||||||||||||||||
Mid-Atlantic | 11,172 | 11,691 | (519 | ) | (4.4 | %) | ||||||||||
Midwest | 21,995 | 23,344 | (1,349 | ) | (5.8 | %) | ||||||||||
Fossil and renewable generation | ||||||||||||||||
Mid-Atlantic(a)(b) | 2,054 | 2,175 | (121 | ) | (5.6 | %) | ||||||||||
Midwest(c) | 163 | 7 | 156 | n.m. | ||||||||||||
South and West(c) | 638 | 310 | 328 | 105.8 | % | |||||||||||
Purchased power(d) | ||||||||||||||||
Mid-Atlantic | 707 | 414 | 293 | 70.8 | % | |||||||||||
Midwest | 1,659 | 1,568 | 91 | 5.8 | % | |||||||||||
South and West | 2,411 | 2,695 | (284 | ) | (10.5 | %) | ||||||||||
Total supply by region | ||||||||||||||||
Mid-Atlantic | 13,933 | 14,280 | (347 | ) | (2.4 | %) | ||||||||||
Midwest | 23,817 | 24,919 | (1,102 | ) | (4.4 | %) | ||||||||||
South and West | 3,049 | 3,005 | 44 | 1.5 | % | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total supply | 40,799 | 42,204 | (1,405 | ) | (3.3 | %) | ||||||||||
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Six Months Ended June 30, | Variance | % Change | ||||||||||||||
Supply source (GWh) | 2011 | 2010 | ||||||||||||||
Nuclear generation(a) | ||||||||||||||||
Mid-Atlantic | 23,543 | 23,467 | 76 | 0.3 | % | |||||||||||
Midwest | 44,816 | 45,677 | (861 | ) | (1.9 | %) | ||||||||||
Fossil and renewable generation | ||||||||||||||||
Mid-Atlantic(a)(b) | 4,220 | 4,739 | (519 | ) | (11.0 | %) | ||||||||||
Midwest(c) | 320 | 7 | 313 | n.m. | ||||||||||||
South and West(c) | 1,147 | 429 | 718 | 167.4 | % | |||||||||||
Purchased power(d) | ||||||||||||||||
Mid-Atlantic | 1,457 | 877 | 580 | 66.1 | % | |||||||||||
Midwest | 3,071 | 3,482 | (411 | ) | (11.8 | %) | ||||||||||
South and West | 4,593 | 5,396 | (803 | ) | (14.9 | %) | ||||||||||
Total supply by region | ||||||||||||||||
Mid-Atlantic | 29,220 | 29,083 | 137 | 0.5 | % | |||||||||||
Midwest | 48,207 | 49,166 | (959 | ) | (2.0 | %) | ||||||||||
South and West | 5,740 | 5,825 | (85 | ) | (1.5 | %) | ||||||||||
|
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| |||||||||
Total supply | 83,167 | 84,074 | (907 | ) | (1.1 | %) | ||||||||||
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Six Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
Supply source (GWh) | 2010 | 2009 | Variance | % Change | ||||||||||||
Nuclear generation | ||||||||||||||||
Mid-Atlantic (a) | 23,467 | 24,380 | (913 | ) | -3.7 | % | ||||||||||
Midwest | 45,677 | 45,997 | (320 | ) | -0.7 | % | ||||||||||
Fossil and hydro generation | ||||||||||||||||
Mid-Atlantic (b) | 4,739 | 4,908 | (169 | ) | -3.4 | % | ||||||||||
Midwest | 7 | 4 | 3 | 75.0 | % | |||||||||||
South | 429 | 554 | (125 | ) | -22.6 | % | ||||||||||
Purchased power (c) | ||||||||||||||||
Mid-Atlantic | 877 | 873 | 4 | 0.5 | % | |||||||||||
Midwest | 3,482 | 3,825 | (343 | ) | -9.0 | % | ||||||||||
South | 5,396 | 6,655 | (1,259 | ) | -18.9 | % | ||||||||||
Total supply by region | ||||||||||||||||
Mid-Atlantic | 29,083 | 30,161 | (1,078 | ) | -3.6 | % | ||||||||||
Midwest | 49,166 | 49,826 | (660 | ) | -1.3 | % | ||||||||||
South | 5,825 | 7,209 | (1,384 | ) | -19.2 | % | ||||||||||
Total supply | 84,074 | 87,196 | (3,122 | ) | -3.6 | % | ||||||||||
(a) | Includes Generation’s proportionate share of the output of its | |
(b) | Includes generation in New | |
(c) | Includes generation from Exelon Wind, acquired in December, 2010, of 154 GWh and 309 GWh in the Midwest and 431 GWh and 789 GWh in the South and West for the three months and six months ended June 30, 2011, respectively. |
(d) | Includes non-PPA purchases of |
Generation’s sales are summarized below:
Three Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
Sales (GWh) (a) | 2010 | 2009 | Variance | % Change | ||||||||||||
ComEd (b) | 1,895 | 4,215 | (2,320 | ) | -55.0 | % | ||||||||||
PECO | 10,044 | 9,277 | 767 | 8.3 | % | |||||||||||
Market and retail (c) | 30,265 | 29,480 | 785 | 2.7 | % | |||||||||||
Total electric sales | 42,204 | 42,972 | (768 | ) | -1.8 | % | ||||||||||
Six Months Ended | ||||||||||||||||
June 30, | ||||||||||||||||
Sales (GWh) (a) | 2010 | 2009 | Variance | % Change | ||||||||||||
ComEd (b) | 5,323 | 9,752 | (4,429 | ) | -45.4 | % | ||||||||||
PECO | 20,272 | 19,500 | 772 | 4.0 | % | |||||||||||
Market and retail (c) | 58,479 | 57,944 | 535 | 0.9 | % | |||||||||||
Total electric sales | 84,074 | 87,196 | (3,122 | ) | -3.6 | % | ||||||||||
Three Months Ended June 30, | Variance | % Change | ||||||||||||||
Sales (GWh)(a) | 2011 | 2010 | ||||||||||||||
ComEd(b) | — | 1,895 | (1,895 | ) | (100.0 | %) | ||||||||||
PECO(c) | — | 10,044 | (10,044 | ) | (100.0 | %) | ||||||||||
Market and retail(d) | 40,799 | 30,265 | 10,534 | 34.8 | % | |||||||||||
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| |||||||||
Total electric sales | 40,799 | 42,204 | (1,405 | ) | (3.3 | %) | ||||||||||
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Six Months Ended June 30, | Variance | % Change | ||||||||||||||
Sales (GWh)(a) | 2011 | 2010 | ||||||||||||||
ComEd(b) | — | 5,323 | (5,323 | ) | (100.0 | %) | ||||||||||
PECO(c) | — | 20,272 | (20,272 | ) | (100.0 | %) | ||||||||||
Market and retail(d) | 83,167 | 58,479 | 24,688 | 42.2 | % | |||||||||||
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| |||||||||
Total electric sales | 83,167 | 84,074 | (907 | ) | (1.1 | %) | ||||||||||
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(a) | Excludes physical trading volumes of | |
(b) | Represents sales under the 2006 ComEd auction. | |
(c) | Represents sales under the full requirements PPA, which expired on December 31, 2010. |
(d) | Includes sales under the ComEd RFP, settlements under the ComEd swap and sales |
107
Three Months Ended | ||||||||||||
June 30, | ||||||||||||
$/MWh | 2010 | 2009 | % Change | |||||||||
Mid-Atlantic (a) | $ | 40.83 | $ | 45.76 | -10.8 | % | ||||||
Midwest (a) (b) | $ | 40.78 | $ | 41.73 | -2.3 | % | ||||||
South | $ | (14.31 | ) | $ | (6.85 | ) | -108.9 | % | ||||
Electric revenue net of purchased power and fuel expense per MWh (c) | $ | 36.87 | $ | 38.96 | -5.4 | % |
Six Months Ended | ||||||||||||
June 30, | ||||||||||||
$/MWh | 2010 | 2009 | % Change | |||||||||
Mid-Atlantic (a) | $ | 41.14 | $ | 45.65 | -9.9 | % | ||||||
Midwest (a) (b) | $ | 40.88 | $ | 41.95 | -2.6 | % | ||||||
South | $ | (15.62 | ) | $ | (8.04 | ) | -94.3 | % | ||||
Electric revenue net of purchased power and fuel expense per MWh (c) | $ | 37.06 | $ | 39.09 | -5.2 | % |
Three Months Ended June 30, | % Change | |||||||||||
$/MWh | 2011 | 2010 | ||||||||||
Mid-Atlantic(a)(b) | $ | 58.92 | $ | 40.83 | 44.3 | % | ||||||
Midwest(a)(c) | $ | 37.28 | $ | 40.78 | (8.6 | %) | ||||||
South and West | $ | (3.61 | ) | $ | (14.31 | ) | 74.9 | % | ||||
Electric revenue net of purchased power and fuel expense per MWh(d) | $ | 41.59 | $ | 36.87 | 12.8 | % |
Six Months Ended June 30, | % Change | |||||||||||
$/MWh | 2011 | 2010 | ||||||||||
Mid-Atlantic(a)(b) | $ | 59.45 | $ | 41.14 | 44.5 | % | ||||||
Midwest(a)(c) | $ | 38.40 | $ | 40.88 | (6.1 | %) | ||||||
South and West | $ | (2.44 | ) | $ | (15.62 | ) | 84.4 | % | ||||
Electric revenue net of purchased power and fuel expense per MWh(d) | $ | 42.97 | $ | 37.06 | 16.0 | % |
(a) | Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively. | |
(b) | Includes sales to PECO of $116 million (1,636 GWh) and $259 million (3,669 GWh) for the three and six months ended June 30, 2011. Excludes compensation under the reliability-must-run rate schedule. |
(c) | Includes sales to ComEd |
Revenue net of purchased power and fuel expense per MWh represents the average margin per MWh of electricity sold during the three and six months ended June 30, |
Mid-Atlantic
Three Months Ended June 30, 20102011 Compared to Three Months Ended June 30, 20092010. The $99 million decreaseincrease in revenue net of purchased power and fuel expense in the Mid-Atlantic of $238 million was primarily due to unfavorable pricing related toincreased realized margins on the volumes previously sold under Generation’s PPA with PECO. Additionally, decreased production from owned generation and increased sales to PECO, resulted in less energy available for market and retail sales.
Six Months Ended June 30, 20102011 Compared to Six Months Ended June 30, 2009.2010. The $180 million decreaseincrease in revenue net of purchased power and fuel expense in the Mid-Atlantic of $540 million was primarily due to unfavorable pricing related toincreased realized margins on the volumes previously sold under Generation’s PPA with PECO. Additionally, decreased production from owned generation and increased sales to PECO, resulted in less energy available for market and retail sales.
Midwest
Three Months Ended June 30, 20102011 Compared to Three Months Ended June 30, 20092010. The $1 million decrease in revenue net of purchased power and fuel expense in the Midwest of $129 million was primarily due to decreased realized margins in 2011 for the volumes previously sold under the 2006 ComEd auction contracts, increases in the price oflower nuclear fuelvolumes and unfavorable market conditionshigher congestion costs. These decreases were partially offset by higher volumes available for marketfavorable settlements under the ComEd swap and retail sales dueincreased capacity revenues, in addition to higher nuclear generation.
Six Months Ended June 30, 20102011 Compared to Six Months Ended June 30, 2009.2010. The $80 million decrease in revenue net of purchased power and fuel expense in the Midwest of $159 million was primarily due to decreased realized margins in 2011 for the volumes previously sold under the 2006 ComEd auction contracts increasesand higher congestion costs. These decreases were partially offset by increased capacity revenues and favorable settlements under the ComEd swap, in addition to the priceadditional revenue from the acquisition of nuclear fuelExelon Wind in December 2010.
South and unfavorable market conditions.
In the South and West, there are certain long-term purchase power agreements that have fixed capacity payments based on unit availability. The extent to which these fixed payments are recovered is dependent on market conditions.
Three Months Ended June 30, 20102011 Compared to Three Months Ended June 30, 20092010. The decreaseincrease in revenue net of purchased power and fuel expense in the South and West of $18$32 million was primarily due to lowerthe additional revenue from the acquisition of the Exelon Wind business in December 2010 and higher realized margins due to outage activity and unfavorablefavorable market conditions.
108
Mark-to-market
Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations.
Three Months Ended June 30, 20102011 Compared to Three Months Ended June 30, 20092010. Mark-to-market losses on power hedging activities were $150$94 million for the three months ended June 30, 2010,2011, including the impact of the changes in ineffectiveness, compared to losses of $160$150 million for the three months ended June 30, 2009.2010. Mark-to-market gainslosses on fuel hedging activities were $30 million for the three months ended June 30,
2011 compared to gains of $26 million for the three months ended June 30, 2010 compared2010. See Notes 5 and 6 of the Combined Notes to the Consolidated Financial Statements for information on losses of $13associated with mark-to-market derivatives.
Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. Mark-to-market losses on power hedging activities were $189 million for the threesix months ended June 30, 2009.2011, including the impact of the changes in ineffectiveness, compared to gains of $35 million for the six months ended June 30, 2010. Mark-to-market losses on fuel hedging activities were $83 million for the six months ended June 30, 2011 compared to gains of $74 million for the six months ended June 30, 2010. See Notes 45 and 6 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
SixOther
Three Months Ended June 30, 20102011 Compared to SixThree Months Ended June 30, 20092010. Mark-to-market gains on power hedging activities were $35 million forThe increase in other is primarily due to the six months ended June 30, 2010, including the impacttermination of the changesComEd and Ameren customer credits associated with the Illinois Settlement Legislation in ineffectiveness, compared to gains of $40 million for2010 and compensation under the six months ended June 30, 2009. Mark-to-market gains on fuel hedging activities were $74 million for the six months ended June 30, 2010 compared to losses of $28 million for the six months ended June 30, 2009. See Notes 4 and 6reliability-must-run rate schedule further described in Note 11 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
Six Months Ended June 30, 20102011 Compared to Six Months Ended June 30, 20092010. The increase in other revenues wasis primarily due to $54 million in reduced customer credits issued tothe termination of the ComEd and Ameren customer credits associated with the Illinois Settlement Legislation in 2010, additional other wholesale fuel sales and compensation under the reliability-must-run rate schedule further described in Note 311 of the Combined Notes to the Consolidated Financial Statements.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Nuclear fleet capacity factor(a) | 94.8 | % | 93.9 | % | 93.6 | % | 95.0 | % | ||||||||
Nuclear fleet production cost per MWh(a) | $ | 16.61 | $ | 15.52 | $ | 17.73 | $ | 15.75 |
Nuclear Fleet Capacity Factor and Production Costs
The following table presents nuclear fleet operating data for the three and six months ended June 30, 2011 as compared to the same periods in June 30, 2010, for the Generation-operated plants. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Nuclear fleet production cost is defined as the costs to produce one MWh of energy, including fuel, materials, labor, contracting and other miscellaneous costs, but excludes depreciation and certain other non-production related overhead costs. Generation considers capacity factor and production costs useful measures to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Nuclear fleet capacity factor(a) | 89.6 | % | 94.8 | % | 92.2 | % | 93.6 | % | ||||||||
Nuclear fleet production cost per MWh(a) | $ | 19.41 | $ | 16.61 | $ | 19.06 | $ | 17.73 |
(a) | Excludes Salem, which is operated by PSEG Nuclear, LLC. |
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Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. The nuclear fleet capacity factor decreased primarily due to more non-refueling outage days, excluding Salem outages, during the six months ended June 30, 2011 compared to the same period in 2010 . For the six months ended June 30, 2011 and 2010, and 2009, refuelingnon-refueling outage days totaled 14538 and 91,20, respectively. The increase in refueling outage days is primarily due to the increase in the number of refueling outages performed in 2010 compared to 2009. Additionally, the 2009 refueling outage at Three Mile Island Generating Station extended 23 days into 2010. AHigher nuclear fuel costs, higher plant operating and maintenance expense and a lower number of net MWhs generated higher operating and maintenance costs associated with the higher number of refueling outages and higher nuclear fuel costs resulted in higher production cost per MWh for the six months ended June 30, 20102011 as compared to the same period in 2009.
Operating and Maintenance Expense
The changes in operating and maintenance expense for the three and six months ended June 30, 20102011 compared to the same period in 2009,2010, consisted of the following:
Three Months | Six Months | |||||||
Ended June 30, | Ended June 30, | |||||||
Increase | Increase | |||||||
(Decrease) | (Decrease) | |||||||
Impairment of certain generating assets (a) | $ | — | $ | (223 | ) | |||
Labor, other benefits, contracting and materials (b) | (3 | ) | (20 | ) | ||||
Severance (c) | (15 | ) | (15 | ) | ||||
Nuclear refueling outage costs, including the co-owned Salem plant (d) | 4 | 61 | ||||||
Pension and non-pension postretirement benefits expense | 5 | 14 | ||||||
Other | 11 | (2 | ) | |||||
Increase (decrease) in operating and maintenance expense | $ | 2 | $ | (185 | ) | |||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Labor, other benefits, contracting and materials | $ | 11 | $ | 48 | ||||
Exelon Wind(a) | 13 | 21 | ||||||
Nuclear refueling outage costs, including the co-owned Salem plant(b) | 45 | 10 | ||||||
Pension and non-pension postretirement benefits expense | (5 | ) | (9 | ) | ||||
Other | 8 | 15 | ||||||
Increase in operating and maintenance expense | $ | 72 | $ | 85 | ||||
(a) | Includes the costs of $10 million and $15 million for the | |
(b) | ||
Reflects the impact of increased planned refueling outages |
Depreciation and Amortization
The increase in depreciation and amortization for the three and six months ended June 30, 2011 as compared to the three and six months ended June 30, 2010 Comparedwas primarily due to Three Months Ended June 30, 2009.higher plant balances due to capital additions, upgrades to existing facilities and the acquisition of Exelon Wind. The increase in depreciation and amortization expense was primarilyalso due to the change in the estimated useful lives associated with the plant shutdownsshutdown of Eddystone and Cromby announced in December 2009.the second and third quarters of 2010. The change in estimated useful lives is further described in Note 811 of the Combined Notes to Consolidated Financial Statements resulted in an increase of $20 million for the three months ended June 30, 2010 compared to the same period in 2009. Additionally, Generation completed a depreciation rate study during the first quarter of 2010, which resulted in a change in depreciation rate. The change in depreciation rate resulted in an increase of $5 million for the three months ended June 30, 2010 compared to the same period in 2009. The remaining increase in depreciation expense primarily reflected higher plant balances due to capital additions and upgrades to existing facilities.
Statements.
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The increase in taxes other than income for the three and six months ended June 30, 2011 as compared to the three and six months ended June 30, 2010 was primarily due to increased propertygross receipt taxes related to retail sales in the Mid-Atlantic region. These gross receipt taxes are recovered in revenue, and as a result, have no net impact to Generation’s nuclear facilities.
Interest Expense
The increase in interest expense for the three and six months ended June 30, 2011 as compared to the three and six months ended June 30, 2010 was primarily due to a netan increase in long-term debt outstanding as a result of issuances in 2009, furtherthe second half of 2010.
Other, Net
Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. Other, net primarily reflects the change in the net unrealized gains (losses) related to the NDT funds of the Non-Regulatory
Agreement Units as described in Note 9the table below. Other, net also reflects $19 million of income in 2011 compared to $54 million of expense in 2010 related to the contractual elimination of income tax expense associated with the NDT funds of the 2009 Form 10-K.Regulatory Agreement Units. The increase in long-term debt resultedother, net also reflects the impact of a $32 million one-time interest income from the NDT fund special transfer tax deduction recognized in higher interest expensethe second quarter of approximately $10 million for the three months ended June 30, 2010 compared to the same period in 2009.
Six Months Ended June 30, 20102011 Compared to Six Months Ended June 30, 2009.2010. The increase in interest expense was primarily due to a net increase in long-term debt outstanding as a result of issuances in 2009, further described in Note 9 of the 2009 Form 10-K. The increase in long-term debt resulted in higher interest expense of approximately $19 million for the six months ended June 30, 2010 compared to the same period in 2009.
The following table provides unrealized and realized gains and losses on the NDT funds of the Non-Regulatory Agreement Units recognized in other, net for the three and six months ended June 30, 20102011 and 2009:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net unrealized gains (losses) on decommissioning trust funds | $ | (94 | ) | $ | 115 | $ | (59 | ) | $ | 51 | ||||||
Net realized losses on sale of decommissioning trust funds | $ | — | $ | (3 | ) | $ | — | $ | (7 | ) |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net unrealized gains (losses) on decommissioning trust funds | $ | 11 | $ | (94 | ) | $ | 54 | $ | (59 | ) | ||||||
Net realized losses on sale of decommissioning trust funds | $ | — | $ | — | $ | (2 | ) | $ | — |
Effective Income Tax Rate
The effective income tax rate was 8.4%34.7% and 31.5%37.8% for the three and six months ended June 30, 2010,2011, respectively, compared to 40.9%8.4% and 35.7%31.5% for the same periods during 2009.2010. See Note 98 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
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Three Months | Favorable | Six Months | Favorable | |||||||||||||||||||||
Ended June 30, | (Unfavorable) | Ended June 30, | (Unfavorable) | |||||||||||||||||||||
2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
Operating revenues | $ | 1,499 | $ | 1,389 | $ | 110 | $ | 2,914 | $ | 2,942 | $ | (28 | ) | |||||||||||
Purchased power expense | 771 | 715 | (56 | ) | 1,524 | 1,598 | 74 | |||||||||||||||||
Revenue net of purchased power expense (a) | 728 | 674 | 54 | 1,390 | 1,344 | 46 | ||||||||||||||||||
Other operating expenses | ||||||||||||||||||||||||
Operating and maintenance | 276 | 270 | (6 | ) | 435 | 522 | 87 | |||||||||||||||||
Operating and maintenance for regulatory required programs | 21 | 14 | (7 | ) | 40 | 25 | (15 | ) | ||||||||||||||||
Depreciation and amortization | 131 | 124 | (7 | ) | 261 | 246 | (15 | ) | ||||||||||||||||
Taxes other than income | 44 | 57 | 13 | 107 | 136 | 29 | ||||||||||||||||||
�� | ||||||||||||||||||||||||
Total other operating expenses | 472 | 465 | (7 | ) | 843 | 929 | 86 | |||||||||||||||||
Operating income | 256 | 209 | 47 | 547 | 415 | 132 | ||||||||||||||||||
Other income and deductions | ||||||||||||||||||||||||
Interest expense, net | (134 | ) | (75 | ) | (59 | ) | (218 | ) | (159 | ) | (59 | ) | ||||||||||||
Other, net | 8 | 55 | (47 | ) | 11 | 87 | (76 | ) | ||||||||||||||||
Total other income and deductions | (126 | ) | (20 | ) | (106 | ) | (207 | ) | (72 | ) | (135 | ) | ||||||||||||
Income before income taxes | 130 | 189 | (59 | ) | 340 | 343 | (3 | ) | ||||||||||||||||
Income taxes | 121 | 73 | (48 | ) | 215 | 113 | (102 | ) | ||||||||||||||||
Net income | $ | 9 | $ | 116 | $ | (107 | ) | $ | 125 | $ | 230 | $ | (105 | ) | ||||||||||
Three Months Ended June 30, | Favorable (Unfavorable) Variance | Six Months Ended June 30, | Favorable (Unfavorable) Variance | |||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||
Operating revenues | $ | 1,444 | $ | 1,499 | $ | (55 | ) | $ | 2,910 | $ | 2,914 | $ | (4 | ) | ||||||||||
Purchased power expense | 716 | 771 | 55 | 1,505 | 1,524 | 19 | ||||||||||||||||||
Revenue net of purchased power expense(a) | 728 | 728 | — | 1,405 | 1,390 | 15 | ||||||||||||||||||
Other operating expenses | ||||||||||||||||||||||||
Operating and maintenance | 245 | 276 | 31 | 493 | 435 | (58 | ) | |||||||||||||||||
Operating and maintenance for regulatory required programs | 23 | 21 | (2 | ) | 41 | 40 | (1 | ) | ||||||||||||||||
Depreciation and amortization | 136 | 131 | (5 | ) | 270 | 261 | (9 | ) | ||||||||||||||||
Taxes other than income | 70 | 44 | (26 | ) | 147 | 107 | (40 | ) | ||||||||||||||||
Total other operating expenses | 474 | 472 | (2 | ) | 951 | 843 | (108 | ) | ||||||||||||||||
Operating income | 254 | 256 | (2 | ) | 454 | 547 | (93 | ) | ||||||||||||||||
Other income and deductions | ||||||||||||||||||||||||
Interest expense, net | (86 | ) | (134 | ) | 48 | (172 | ) | (218 | ) | 46 | ||||||||||||||
Other, net | 4 | 8 | (4 | ) | 8 | 11 | (3 | ) | ||||||||||||||||
Total other income and deductions | (82 | ) | (126 | ) | 44 | (164 | ) | (207 | ) | 43 | ||||||||||||||
Income before income taxes | 172 | 130 | 42 | 290 | 340 | (50 | ) | |||||||||||||||||
Income taxes | 58 | 121 | 63 | 107 | 215 | 108 | ||||||||||||||||||
Net income | $ | 114 | $ | 9 | $ | 105 | $ | 183 | $ | 125 | $ | 58 | ||||||||||||
(a) | ComEd evaluates its operating performance using the measure of revenue net of purchased power expense. ComEd believes that revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
Net income
Three Months Ended June 30, 20102011 Compared to Three Months Ended June 30, 2009.2010. ComEd’s net income for the three months ended June 30, 20102011 was lowerhigher than the same period in 20092010 primarily due principally, to one-time net benefits recognized pursuant to the May 2011 ICC order in ComEd’s 2010 Rate Case and the remeasurement of uncertain income tax positions in 2009 and 2010 related to the 1999 sale of ComEd’s fossil generating assets. These remeasurementsThe remeasurement resulted in increased interest expense and income tax expense recorded in the second quarter of 2010 and increased interest income recorded in the second quarter of 2009. ComEd’s operating and maintenance expense remained relatively consistent, reflecting severance expense recorded in the second quarter of 2009 associated with the 2009 restructuring plan and higher incremental storm costs.2010. These reductionsincreases to net income were partially offset by higher revenues due to favorable weather and lower taxes other than income taxes, reflecting the accrual of estimated future Illinois utility distribution tax refunds for the 2008 and 2009 tax years recorded in the second quarter of 2010 of the Illinois utility distribution tax for the 2008 and 2009 tax years.
Six Months Ended June 30, 20102011 Compared to Six Months Ended June 30, 2009.2010. ComEd’s net income for the six months ended June 30, 20102011 was lowerhigher than the same period in 20092010 primarily due principally,one-time net benefits
recognized pursuant to the May 2011 ICC Order in ComEd’s 2010 Rate Case and the impact of the remeasurement of uncertain income tax positions in 2009 and 2010 related to the 1999 sale of ComEd’s fossil generating assets. These remeasurementsThe remeasurement resulted in increased interest expense and income tax expense recorded in the second quarter of 2010, and increased interest income recorded in the second quarter of 2009. Net income was also reduced by higher incremental storm costs, the first quarter 2009 impact of benefits associated with an Illinois Supreme Court decision granting Illinois Investment Tax Credits to ComEd which were reversed in the third quarter of 2009, and the first quarter 2010 impact of Federal health care legislation signed into law in March 2010. These reductionsincreases to net income were partially offset by the reversal of 2008 and 2009 under-collection of annual uncollectible accounts expense due tobenefit recorded in 2010 resulting from the February 2010ICC’s approval by the ICC of ComEd’s uncollectible accounts expense rider mechanism lower taxes other than income taxes, reflectingand the accrual of estimated future refunds recorded in the second quarter of 2010 of the Illinois utility distribution tax refunds for the 2008 and 2009 tax years and higher revenue netrecorded in the second quarter of purchased power expense due to favorable weather.
2010.
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There are certain drivers to revenue that are fully offset by their impact on purchased power expense, such as commodity procurement costs and customer choice programs. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Therefore, fluctuations in electricity procurement costs have no impact on electric revenue net of purchased power expense. See Note 3 of the Combined Notes to the Consolidated Financial Statements and Note 2 of the 2009 Form 10-K for additional information on ComEd’s electricity procurement process.
Electric revenues and purchased power expense are equally affected by fluctuations in customers’ purchases from competitive electric generation suppliers. All ComEd customers have the ability to purchase electricity from an alternative electric generation supplier. The customer choice of electric generation supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied electricity.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Number of customers at period end | 57,209 | 48,900 | 57,209 | 48,900 | ||||||||||||
Percentage of total retail customers | 2 | % | 1 | % | 2 | % | 1 | % | ||||||||
Volume (GWh) | 11,526 | 10,851 | 22,707 | 21,965 | ||||||||||||
Percentage of total retail deliveries | 54 | % | 53 | % | 52 | % | 51 | % |
The changes in ComEd’s electric revenue net of purchased power expense for the three and six months ended June 30, 20102011 compared to the same periodperiods in 20092010 consisted of the following:
Three Months Ended | Six Months Ended | |||||||
June 30, 2010 | June 30, 2010 | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Uncollectible accounts recovery | $ | 17 | $ | 17 | ||||
Energy efficiency and demand response programs and other programs | 7 | 15 | ||||||
Weather — delivery | 16 | 11 | ||||||
Volume — delivery | 6 | 5 | ||||||
Other | 8 | (2 | ) | |||||
Total increase (decrease) | $ | 54 | $ | 46 | ||||
Three Months Ended June 30, 2011 | Six Months Ended June 30, 2011 | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Reversal of revenue subject to refund | $ | 17 | $ | 17 | ||||
Pricing (2010 Rate Case) | 13 | 13 | ||||||
Transmission | 2 | 5 | ||||||
Volume — delivery | (3 | ) | (5 | ) | ||||
Weather — delivery | (7 | ) | (1 | ) | ||||
Over-recovered uncollectible accounts | (10 | ) | (10 | ) | ||||
Uncollectible accounts recovery, net | (8 | ) | 4 | |||||
Revenue subject to refund (2007 Rate Case) | (11 | ) | (28 | ) | ||||
Other | 7 | 20 | ||||||
Total increase | $ | — | $ | 15 | ||||
Uncollectible Accounts RecoveryReversal of revenue subject to refund
Subsequent to ICC approval, ComEd began billing customers for Cash Working Capital (CWC) through its energy procurement rider on June 1, 2010 reflecting the costs included in Illinois providing public utility companies withComEd’s original request to amend the abilitytariff. Because of the uncertainty regarding the methodology for determining CWC recovery, ComEd had been recording a reserve against a portion of these billings. The ICC order in the 2010 Rate Case clarifies the method for determining CWC, and as a result, ComEd reversed a $17 million reserve during the second quarter of 2011. See Note 3 of the Combined Notes to recover from or refund to customersConsolidated Financial Statements for additional information.
Pricing (2010 Rate Case)
The ICC issued an order in the difference between the utility’s2010 Rate Case approving an increase in ComEd’s annual uncollectible accounts expense and amounts collectedrevenue requirement. The order became effective June 1, 2011 resulting in rates annually through a rider mechanism, starting with 2008 and prospectively. Recovery began$13 million increase in April 2010, and duringrevenues for the three and six months ended June 30, 2011 compared to the same periods in 2010. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission
ComEd’s transmission rates are established based on a FERC-approved formula. ComEd’s most recent annual formula rate update, filed in May 2011, reflects actual 2010 ComEd recognized recoveryexpenses and investments plus forecasted 2011 capital additions. Transmission revenues net of $17 million associated with this rider mechanism. These amounts were offset by an equal amountpurchased power expense vary from year to year based upon fluctuations in the underlying costs and investments being recovered. See Note 3 of amortizationthe Combined Notes to Consolidated Financial Statements.
Volume — delivery
Revenues net of regulatory assets reflected in operating and maintenance expense.
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Weather—Weather — delivery
Revenues net of purchased power expense were higherlower in the three and six months ended June 30, 20102011 compared to the same periods in 20092010 due to favorableunfavorable weather conditions. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased customer usage and delivery of electricity. Conversely, mild weather reduces demand.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in ComEd’s service territory.territory with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the three and six months ended June 30, 20102011 and 2009,2010, consisted of the following:
% Change | ||||||||||||||||||||
Heating and Cooling Degree-Days | 2010 | 2009 | Normal | From 2009 | From Normal | |||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||
Heating Degree-Days | 519 | 768 | 766 | (32.4) | % | (32.2) | % | |||||||||||||
Cooling Degree-Days | 312 | 177 | 224 | 76.3 | % | 39.3 | % | |||||||||||||
Six Months Ended June 30, | ||||||||||||||||||||
Heating Degree-Days | 3,629 | 4,088 | 3,974 | (11.2) | % | (8.7) | % | |||||||||||||
Cooling Degree-Days | 312 | 177 | 224 | 76.3 | % | 39.3 | % |
% Change | ||||||||||||||||||||
Heating and Cooling Degree-Days | 2011 | 2010 | Normal | From 2010 | From Normal | |||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||
Heating Degree-Days | 823 | 519 | 766 | 58.6 | % | 7.4 | % | |||||||||||||
Cooling Degree-Days | 237 | 312 | 224 | (24.0 | )% | 5.8 | % | |||||||||||||
Six Months Ended June 30, | ||||||||||||||||||||
Heating Degree-Days | 4,155 | 3,629 | 3,974 | 14.5 | % | 4.6 | % | |||||||||||||
Cooling Degree-Days | 237 | 312 | 224 | (24.0 | )% | 5.8 | % |
On July 20, 2011, ComEd set a new record for highest daily peak load experienced to date of 23,753 MWs. The impacts of July weather on revenues net of purchased power expense increased aswill be reflected in third quarter results.
Over-recovered uncollectible accounts
In 2009, comprehensive legislation was enacted into law in Illinois providing public utility companies with the ability to recover from or refund to customers the difference between the utility’s annual uncollectible
accounts expense and amounts collected in rates annually through a rider mechanism, starting with 2008 and prospectively. Recovery began in April 2010.
As of June 30, 2011, ComEd was in a cumulative over-recovery position of $10 million under this rider mechanism. As a result, of higher delivery volume, exclusiveComEd recorded a reduction in revenues and an offsetting regulatory liability to reflect this over-recovery. Based on the recent rate order and the provisions of the effectsuncollectible accounts tariff, ComEd anticipates that it will continue to be in an over-collection position during the remainder of weather, reflecting increased customer growth2011.
Uncollectible accounts recovery
Represents recoveries under ComEd’s uncollectible accounts tariff.
Revenue subject to refund (2007 Rate Case)
ComEd recorded estimated refund obligations of $11 million and increased average usage per customer for$28 million during the three and six months ended June 30, 2010, compared to2011, respectively, as a result of the same periods in 2009.
Other
Other revenues were higher during the three months ended June 30, 2010 compared to the same period in 2009 and lower during the six months ended June 30, 20102011 compared to the same periodperiods in 2009.2010. Other revenues, which can vary period to period, include transmissionrental revenues, revenues related to late payment charges, rental revenues,assistance provided to other utilities through mutual assistance programs and recoveries of environmental remediation costs associated with MGP sites.
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The changes in operating and maintenance expense for the three and six months ended June 30, 20102011 compared to the same periodperiods in 2009,2010, consisted of the following:
Three Months | Six Months | |||||||
Ended June 30 | Ended June 30 | |||||||
Increase | Increase | |||||||
(Decrease) | (Decrease) | |||||||
Changes in under-recovered uncollectible accounts (a) | $ | 34 | $ | 21 | ||||
Incremental storm-related costs | 14 | 12 | ||||||
Wages and salaries | (2 | ) | (9 | ) | ||||
Corporate allocations | (5 | ) | (9 | ) | ||||
Uncollectible account expense (b) | (19 | ) | (9 | ) | ||||
Contracting | — | (12 | ) | |||||
2009 restructuring plan severance charges | (18 | ) | (18 | ) | ||||
2010 ICC Order (c) | — | (60 | ) | |||||
Other | 2 | (3 | ) | |||||
Increase (Decrease) in operating and maintenance expense | $ | 6 | $ | (87 | ) | |||
Three Months Ended June 30 | Six Months Ended June 30 | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Uncollectible accounts expense(a) | ||||||||
One-time impact of 2010 ICC order(b) | $ | — | $ | 60 | ||||
Recovery, net(c) | (25 | ) | (8 | ) | ||||
Provision | 7 | 2 | ||||||
(18 | ) | 54 | ||||||
Labor, other benefits, contracting and materials | 17 | 33 | ||||||
Storm-related costs | 1 | 5 | ||||||
Discrete impacts from 2010 Rate Case order(d) | (32 | ) | (32 | ) | ||||
Other | 1 | (2 | ) | |||||
Increase (Decrease) in operating and maintenance expense | $ | (31 | ) | $ | 58 | |||
(a) | ||
On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs filed in accordance with Illinois legislation providing public utilities the ability to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism starting with 2008 and prospectively. |
(b) | As a result of the February 2010 ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense for the |
(c) | Represents impacts on recoveries under ComEd’s uncollectible accounts tariff. |
(d) | In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time net benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon’s 2009 restructuring plan. |
On July 11, 2011, a significant wind and lightning storm affected more than 850,000 customers in ComEd’s service territory; one of the worst storms in terms of damage and customer impact in ComEd’s history. ComEd’s restoration efforts included significant costs associated with employee overtime, support from other utilities in other states and incremental equipment and supplies. ComEd estimates that the restoration efforts included operating and maintenance expense and capital expenditures of approximately $55 million and $25 million, respectively, for the third quarter. The vast majority of the operating and maintenance expenses are incremental to ComEd’s normal budget for summer storm activity. As the aforementioned outages resulted directly from weather events outside of ComEd’s control, ComEd intends to request a waiver from the provisions of the Illinois Public Utilities Act that could require damage compensation to customers.
Operating and Maintenance Expense for Regulatory Required Programs
Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.
Depreciation and Amortization Expense
Depreciation and amortization expense increased during the three and six months ended June 30, 20102011 compared to the same periods in 20092010 primarily due to higher plant balances.
Taxes Other Than Income
Taxes other than income taxes decreasedincreased during the three and six months ended June 30, 20102011 compared to the same periodsperiod in 20092010 primarily reflecting the accrual of estimated future refunds of Illinois utility distribution tax recorded in the second quarter of 2010 for the 2008 and 2009 tax years. Historically,Previously, ComEd hashad recorded refunds of the Illinois utility distribution tax when received. ComEd believes it now hasDue to sufficient, reliable evidence, to record and supportComEd began in June 2010 recording an estimated receivable associated with the anticipated refund for the 2008 and 2009Illinois utility distribution tax years.
Interest Expense, Netnet
Interest expense increaseddecreased during the three and six months ended June 30, 20102011 compared to the same periodsperiod in 20092010 primarily due to $59 million of interest expense associated with the remeasurement of uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets recorded in the second quarter of 2010. This increase was partially offset by higher interest expense associated with higher outstanding debt balances. See Note 98 of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Netnet
Other, net decreasedremained relatively level for the three and six months ended June 30, 20102011 compared to the same periods in 2009 primarily due to $29 million of interest income recorded in the first quarter of 2009 associated with the 2009 Illinois Supreme Court ruling concerning ComEd’s claim for refunds for Illinois investment tax credits, which was reversed in the third quarter of 2009. In addition, $60 million of interest income was recorded in the second quarter of 2009 for uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets. These decreases were partially offset by an other-than-temporary impairment of $7 million recorded to ComEd’s investment held in Rabbi trusts during the second quarter of 2009.2010. See Note 1014 of the 2009 Form 10-KCombined Notes to Consolidated Financial Statements for additional information.
further details on the components of Other, Net.
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The effective income tax rate was 93.1%33.7% for the three months ended June 30, 20102011 compared to 38.6%93.1% for the same period during 2009.2010. The effective income tax rate was 63.2%36.9% for the six months ended June 30, 20102011 compared to 32.9%63.2% for the same period during 2009.2010. The increasedecrease in the effective income tax rate isrates was primarily due to the remeasurement of uncertain income tax positions recorded in 2009 andthe second quarter of 2010 related to the
1999 sale of ComEd’s fossil generating assets. The effective income tax rates also decreased as the result of a one-time net benefit recorded in the second quarter of 2011, pursuant to the 2010 Rate Case order, to recover previously incurred income tax expense related to the passage of Federal health care legislation in the first quarter of 2010. See Note 98 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
ComEd Electric Operating Statistics and Revenue Detail
Three Months | Weather- | Six Months | Weather- | |||||||||||||||||||||||||||||
Ended June 30, | % | Normal % | Ended June 30, | % | Normal % | |||||||||||||||||||||||||||
Retail Deliveries to customers (in GWhs) | 2010 | 2009 | Change | Change | 2010 | 2009 | Change | Change | ||||||||||||||||||||||||
Retail Delivery and Sales (a) | ||||||||||||||||||||||||||||||||
Residential | 6,474 | 6,032 | 7.3 | % | 1.6 | % | 13,417 | 13,095 | 2.5 | % | 0.8 | % | ||||||||||||||||||||
Small commercial & industrial | 7,935 | 7,739 | 2.5 | % | (0.1 | )% | 15,864 | 15,889 | (0.2 | )% | (0.9 | )% | ||||||||||||||||||||
Large commercial & industrial | 6,825 | 6,468 | 5.5 | % | 4.3 | % | 13,488 | 13,242 | 1.9 | % | 1.6 | % | ||||||||||||||||||||
Public authorities & electric railroads | 277 | 275 | 0.7 | % | 1.0 | % | 645 | 621 | 3.9 | % | 5.5 | % | ||||||||||||||||||||
Total Retail | 21,511 | 20,514 | 4.9 | % | 1.8 | % | 43,414 | 42,847 | 1.3 | % | 0.5 | % | ||||||||||||||||||||
As of June 30, | ||||||||
Number of Electric Customers | 2010 | 2009 | ||||||
Residential | 3,432,466 | 3,423,387 | ||||||
Small commercial & industrial | 361,326 | 358,897 | ||||||
Large commercial & industrial | 1,982 | 2,033 | ||||||
Public authorities & electric railroads | 5,072 | 5,034 | ||||||
Total | 3,800,846 | 3,789,351 | ||||||
Three Months | Six Months | |||||||||||||||||||||||
Ended June 30, | % | Ended June 30, | % | |||||||||||||||||||||
Electric Revenue | 2010 | 2009 | Change | 2010 | 2009 | Change | ||||||||||||||||||
Retail Delivery and Sales (a) | ||||||||||||||||||||||||
Residential | $ | 829 | $ | 731 | 13.4 | % | $ | 1,606 | $ | 1,577 | 1.8 | % | ||||||||||||
Small commercial & industrial | 415 | 411 | 1.0 | % | 804 | 860 | (6.5 | )% | ||||||||||||||||
Large commercial & industrial | 100 | 93 | 7.5 | % | 197 | 192 | 2.6 | % | ||||||||||||||||
Public authorities & electric railroads | 16 | 14 | 14.3 | % | 33 | 29 | 13.8 | % | ||||||||||||||||
Total Retail | 1,360 | 1,249 | 8.9 | % | 2,640 | 2,658 | (0.7 | )% | ||||||||||||||||
Other Revenue (b) | 139 | 140 | (0.7 | )% | 274 | 284 | (3.5 | )% | ||||||||||||||||
Total Electric Revenues | $ | 1,499 | $ | 1,389 | 7.9 | % | $ | 2,914 | $ | 2,942 | (1.0 | )% | ||||||||||||
Three Months Ended June 30, | % Change | Weather- Normal % Change | ||||||||||||||
Retail Deliveries to customers (in GWhs) | 2011 | 2010 | ||||||||||||||
Retail Delivery and Sales(a) | ||||||||||||||||
Residential | 6,277 | 6,474 | (3.0 | )% | (1.6 | )% | ||||||||||
Small commercial & industrial | 7,763 | 7,935 | (2.2 | )% | (0.2 | )% | ||||||||||
Large commercial & industrial | 6,698 | 6,825 | (1.9 | )% | (0.9 | )% | ||||||||||
Public authorities & electric railroads | 286 | 277 | 3.2 | % | 3.2 | % | ||||||||||
Total Retail | 21,024 | 21,511 | (2.3 | )% | (0.8 | )% | ||||||||||
Six Months Ended June 30, | % Change | Weather- Normal % Change | ||||||||||||||
Retail Deliveries to customers (in GWhs) | 2011 | 2010 | ||||||||||||||
Retail Delivery and Sales(a) | ||||||||||||||||
Residential | 13,231 | 13,417 | (1.4 | )% | (1.7 | )% | ||||||||||
Small commercial & industrial | 15,837 | 15,864 | (0.2 | )% | 0.2 | % | ||||||||||
Large commercial & industrial | 13,517 | 13,488 | 0.2 | % | 0.3 | % | ||||||||||
Public authorities & electric railroads | 616 | 645 | (4.5 | )% | (5.2 | )% | ||||||||||
Total Retail | 43,201 | 43,414 | (0.5 | )% | (0.5 | )% | ||||||||||
As of June 30, | ||||||||||||||||
Number of Electric Customers | 2011 | 2010 | ||||||||||||||
Residential | 3,447,194 | 3,432,466 | ||||||||||||||
Small commercial & industrial | 364,902 | 361,326 | ||||||||||||||
Large commercial & industrial | 2,007 | 1,982 | ||||||||||||||
Public authorities & electric railroads | 4,914 | 5,072 | ||||||||||||||
Total | 3,819,017 | 3,800,846 | ||||||||||||||
Three Months Ended June 30, | % Change | Six Months Ended June 30, | % Change | |||||||||||||||||||||
Electric Revenue | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||
Retail Delivery and Sales(a) | ||||||||||||||||||||||||
Residential | $ | 800 | $ | 829 | (3.5 | )% | $ | 1,634 | $ | 1,606 | 1.7 | % | ||||||||||||
Small commercial & industrial | 386 | 415 | (7.0 | )% | 767 | 804 | (4.6 | )% | ||||||||||||||||
Large commercial & industrial | 95 | 100 | (5.0 | )% | 186 | 197 | (5.6 | )% | ||||||||||||||||
Public authorities & electric railroads | 12 | 16 | (25.0 | )% | 26 | 33 | (21.2 | )% | ||||||||||||||||
Total Retail | 1,293 | 1,360 | (4.9 | )% | 2,613 | 2,640 | (1.0 | )% | ||||||||||||||||
Other Revenue(b) | 151 | 139 | 8.6 | % | 297 | 274 | 8.4 | % | ||||||||||||||||
Total Electric Revenues | $ | 1,444 | $ | 1,499 | (3.7 | )% | $ | 2,910 | $ | 2,914 | (0.1 | )% | ||||||||||||
(a) | Reflects delivery | |
(b) | Other revenue primarily includes transmission revenue from PJM. Other items include rental revenue, revenues related to late payment charges, |
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Three Months | Favorable | Six Months | Favorable | |||||||||||||||||||||
Ended June 30, | (Unfavorable) | Ended June 30, | (Unfavorable) | |||||||||||||||||||||
2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
Operating revenues | $ | 1,269 | $ | 1,204 | $ | 65 | $ | 2,724 | $ | 2,718 | $ | 6 | ||||||||||||
Purchased power and fuel | 579 | 602 | 23 | 1,314 | 1,437 | 123 | ||||||||||||||||||
Revenue net of purchased power and fuel (a) | 690 | 602 | 88 | 1,410 | 1,281 | 129 | ||||||||||||||||||
Other operating expenses | ||||||||||||||||||||||||
Operating and maintenance | 150 | 149 | (1 | ) | 331 | 327 | (4 | ) | ||||||||||||||||
Operating and maintenance for regulatory required programs | 13 | — | (13 | ) | 21 | — | (21 | ) | ||||||||||||||||
Depreciation and amortization | 268 | 230 | (38 | ) | 533 | 455 | (78 | ) | ||||||||||||||||
Taxes other than income | 77 | 69 | (8 | ) | 150 | 135 | (15 | ) | ||||||||||||||||
Total other operating expenses | 508 | 448 | (60 | ) | 1,035 | 917 | (118 | ) | ||||||||||||||||
Operating income | 182 | 154 | 28 | 375 | 364 | 11 | ||||||||||||||||||
Other income and deductions | ||||||||||||||||||||||||
Interest expense, net | (77 | ) | (49 | ) | (28 | ) | (122 | ) | (99 | ) | (23 | ) | ||||||||||||
Loss in equity method investments | — | (6 | ) | 6 | — | (12 | ) | 12 | ||||||||||||||||
Other, net | (1 | ) | 3 | (4 | ) | 4 | 6 | (2 | ) | |||||||||||||||
Total other income and deductions | (78 | ) | (52 | ) | (26 | ) | (118 | ) | (105 | ) | (13 | ) | ||||||||||||
Income before income taxes | 104 | 102 | 2 | 257 | 259 | (2 | ) | |||||||||||||||||
Income taxes | 29 | 31 | 2 | 81 | 76 | (5 | ) | |||||||||||||||||
Net income | 75 | 71 | 4 | 176 | 183 | (7 | ) | |||||||||||||||||
Preferred security dividends | 1 | 1 | — | 2 | 2 | — | ||||||||||||||||||
Net income on common stock | $ | 74 | $ | 70 | $ | 4 | $ | 174 | $ | 181 | $ | (7 | ) | |||||||||||
Three Months Ended June 30, | Favorable (Unfavorable) Variance | Six Months Ended June 30, | Favorable (Unfavorable) Variance | |||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||
Operating revenues | $ | 842 | $ | 1,269 | $ | (427 | ) | $ | 1,996 | $ | 2,724 | $ | (728 | ) | ||||||||||
Purchased power and fuel | 408 | 579 | 171 | 1,042 | 1,314 | 272 | ||||||||||||||||||
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Revenue net of purchased power and fuel(a) | 434 | 690 | (256 | ) | 954 | 1,410 | (456 | ) | ||||||||||||||||
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Other operating expenses | ||||||||||||||||||||||||
Operating and maintenance | 154 | 150 | (4 | ) | 340 | 331 | (9 | ) | ||||||||||||||||
Operating and maintenance for regulatory required programs | 18 | 13 | (5 | ) | 38 | 21 | (17 | ) | ||||||||||||||||
Depreciation and amortization | 50 | 268 | 218 | 98 | 533 | 435 | ||||||||||||||||||
Taxes other than income | 51 | 77 | 26 | 106 | 150 | 44 | ||||||||||||||||||
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Total other operating expenses | 273 | 508 | 235 | 582 | 1,035 | 453 | ||||||||||||||||||
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Operating income | 161 | 182 | (21 | ) | 372 | 375 | (3 | ) | ||||||||||||||||
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Other income and deductions | ||||||||||||||||||||||||
Interest expense, net | (34 | ) | (77 | ) | 43 | (68 | ) | (122 | ) | 54 | ||||||||||||||
Other, net | 3 | (1 | ) | 4 | 8 | 4 | 4 | |||||||||||||||||
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Total other income and deductions | (31 | ) | (78 | ) | 47 | (60 | ) | (118 | ) | 58 | ||||||||||||||
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Income before income taxes | 130 | 104 | 26 | 312 | 257 | 55 | ||||||||||||||||||
Income taxes | 47 | 29 | (18 | ) | 102 | 81 | (21 | ) | ||||||||||||||||
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Net income | 83 | 75 | 8 | 210 | 176 | 34 | ||||||||||||||||||
Preferred security dividends | 1 | 1 | — | 2 | 2 | — | ||||||||||||||||||
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Net income on common stock | $ | 82 | $ | 74 | $ | 8 | $ | 208 | $ | 174 | $ | 34 | ||||||||||||
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(a) | PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report. |
Net Income
The increase in net income for the three and six months ended June 30, 2011 compared to the same periods in 2010 Comparedprimarily related to Three Months Ended June 30, 2009.PECO’sthe new distribution rates effective January 1, 2011 as a result of the 2010 electric and natural gas rate case settlements, decreased storm costs, and decreased interest expense, which reflected the impact of the change in measurement of uncertain tax positions in the second quarter of 2010. These increases in net income increased due to increasedwere partially offset by the net impact of 2010 CTC recoveries reflected in electric operating revenues net of purchased power expense which was partially offset by increased operating expenses and interest expense. The increase in electric revenues net of purchased power expense reflected increased CTC recoveries and favorable weather conditions. PECO’s operating expenses increased as a result of higher scheduled CTC amortization expense, and higher storm related costs,both of which were partially offset by decreased allowance for uncollectible accounts expense. The increase in interest expense was due to additional expense recorded related to a change inceased at the measurement of uncertain tax positions in accordance with accounting guidance. For additional information, see Note 9end of the Combined Notes to the Consolidated Financial Statements.
transition period on December 31, 2010.
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There are certain drivers to operating revenuerevenues that are offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and customer choice programs. GasPECO’s electric generation rates charged to customers were capped until December 31, 2010 in accordance with the 1998 restructuring settlement. Beginning January 1, 2011, PECO’s electric generation rates are based on actual costs incurred through its approved competitive market procurement process. Electric and gas revenues and purchased power and fuel expense are affected by fluctuations in natural gascommodity procurement costs. PECO’s purchasedelectric generation and natural gas cost rates charged to customers are subject to adjustments at least quarterly adjustmentsthat are designed to recover or refund the difference between the actual cost of electric generation and purchased natural gas and the amount included in rates in accordance with the PAPUC’s PGC.GSA and PGC, respectively. Therefore, fluctuations in electric generation and natural gas procurement costs have no impact on gas revenue net of fuel expense. The average purchased gas cost rate per mmcf was $8.07electric and $8.34 for the three months ended June 30, 2010 and 2009, respectively, and $8.01 and $9.40 for the six months ended June 30, 2010 and 2009, respectively. PECO’s electric generation rates charged to customers are capped until December 31, 2010 in accordance with the 1998 Restructuring Settlement. Under PECO’s full requirements PPA with Generation, purchased power costs are based on the energy component of the rates charged to customers. Electric revenues and purchased power expense fluctuate in relation to customer class usage as each customer class is charged a different capped electric generation rate; however, there is no impact on electricgas revenue net of purchased power and fuel expense.
Electric revenues and purchased power expense are also affected by fluctuations in customer participation in the customer choice program. All PECO customers have the choice to purchase energy from a competitive electric generation supplier. A customer’sThe customer choice of electric generation suppliersuppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. Customer choice program activity has no impact on net income. The number of retail customers purchasing energy from a competitive electric generation supplier was 20,900306,923 and 22,80020,931 at June 30, 20102011 and 2009,2010, respectively, representing 1%20% and 2%1% of total retail customers, respectively.
The changes in PECO’s operating revenues net of purchased power and fuel expense for the three months ended June 30, 20102011 compared to the same period in 20092010 consisted of the following:
Increase (Decrease) | ||||||||||||
Electric | Gas | Total | ||||||||||
Weather | $ | 36 | $ | (4 | ) | $ | 32 | |||||
Volume | (2 | ) | — | (2 | ) | |||||||
CTC Recoveries | 55 | — | 55 | |||||||||
Regulatory programs cost recovery | 13 | — | 13 | |||||||||
Other | (11 | ) | 1 | (10 | ) | |||||||
Total increase (decrease) | $ | 91 | $ | (3 | ) | $ | 88 | |||||
Increase (Decrease) | ||||||||||||
Electric | Gas | Total | ||||||||||
Weather | $ | (9 | ) | $ | 2 | $ | (7 | ) | ||||
CTC recoveries | (287 | ) | — | (287 | ) | |||||||
Regulatory program cost recovery | 6 | — | 6 | |||||||||
Pricing | 26 | 2 | 28 | |||||||||
Transmission | 4 | — | 4 | |||||||||
Other | (1 | ) | 1 | — | ||||||||
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Total increase (decrease) | $ | (261 | ) | $ | 5 | $ | (256 | ) | ||||
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The changes in PECO’s operating revenues net of purchased power and fuel expense for the six months ended June 30, 20102011 compared to the same period in 20092010 consisted of the following:
Increase (Decrease) | ||||||||||||
Electric | Gas | Total | ||||||||||
Weather | $ | 32 | $ | (9 | ) | $ | 23 | |||||
Volume | — | 2 | 2 | |||||||||
CTC Recoveries | 101 | — | 101 | |||||||||
Regulatory programs cost recovery | 21 | — | 21 | |||||||||
Other | (17 | ) | (1 | ) | (18 | ) | ||||||
Total increase (decrease) | $ | 137 | $ | (8 | ) | $ | 129 | |||||
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Increase (Decrease) | ||||||||||||
Electric | Gas | Total | ||||||||||
Weather | $ | (7 | ) | $ | 5 | $ | (2 | ) | ||||
Volume | (5 | ) | — | (5 | ) | |||||||
CTC recoveries | (555 | ) | — | (555 | ) | |||||||
Regulatory program cost recovery | 19 | — | 19 | |||||||||
Pricing | 75 | 10 | 85 | |||||||||
Transmission | 10 | — | 10 | |||||||||
Other | (11 | ) | 3 | (8 | ) | |||||||
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Total increase (decrease) | $ | (474 | ) | $ | 18 | $ | (456 | ) | ||||
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The demand for electricity and gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 20102011 compared to the same periods in 2009,2010, electric operating revenues net of purchased power expense were higherlower due to favorableunfavorable weather conditions during the second quarter of 20102011 in PECO’s service territory.territory compared to the second quarter of 2010. The increasedecrease was partially offset by the lowerhigher gas revenues net of fuel expense primarily as a result of unfavorabledue to favorable weather conditions duringin the winter monthsfirst quarter of 2011 in 2010 compared to 2009.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the three and six months ended June 30, 20102011 compared to the same periods in 20092010 and normal weather consisted of the following:
% Change | ||||||||||||||||||||
Heating and Cooling Degree-Days | 2010 | 2009 | Normal | From 2009 | From Normal | |||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||
Heating Degree-Days | 299 | 414 | 458 | (27.8 | )% | (34.7 | )% | |||||||||||||
Cooling Degree-Days | 586 | 352 | 332 | 66.5 | % | 76.5 | % | |||||||||||||
Six Months Ended June 30, | ||||||||||||||||||||
Heating Degree-Days | 2,710 | 2,948 | 2,968 | (8.1 | )% | (8.7 | )% | |||||||||||||
Cooling Degree-Days | 586 | 352 | 332 | 66.5 | % | 76.5 | % |
% Change | ||||||||||||||||||||
Heating and Cooling Degree-Days | 2011 | 2010 | Normal | From 2010 | From Normal | |||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||
Heating Degree-Days | 331 | 299 | 458 | 10.7 | % | (27.7 | )% | |||||||||||||
Cooling Degree-Days | 494 | 586 | 332 | (15.7 | )% | 48.8 | % | |||||||||||||
Six Months Ended June 30, | ||||||||||||||||||||
Heating Degree-Days | 2,837 | 2,710 | 2,968 | 4.7 | % | (4.4 | )% | |||||||||||||
Cooling Degree-Days | 494 | 586 | 332 | (15.7 | )% | 48.8 | % |
On July 22, 2011, PECO set a new record for highest daily peak load experienced to Three and Six Months Ended June 30, 2009. Operatingdate of 8,983 MWs. The impacts of July weather on electric revenues net of purchased power and fuel remained relatively levelexpense will be reflected in third quarter results.
Volume
The decrease in electric operating revenues net of purchased power expense related to delivery volume, exclusive of the effects of weather, for the three and six months ended June 30, 20102011 compared to the same periods in 2009.
CTC Recoveries
The increasedecrease in electric revenues net of purchased power expense as a result ofrelated to CTC recoveries for the three and six months ended June 30, 20102011 compared to the same periods in 20092010 reflected increased deliveries as a resultthe absence of favorable weather conditions and an increase to the CTC charge component of the capped generationthat was included in rates charged to customers which resulted in a decrease to the energy component and reduced purchased power expense under the PPA. Due to lower than expected sales volume in 2009, the CTC increase was necessary to ensure full recovery of2010. PECO fully recovered all stranded costs during the final year of the transition period that expireswhich expired on December 31, 2010.
Regulatory ProgramsProgram Cost Recovery
The increase in electric revenues net of purchased power expense relating to regulatory programs represents theprogram cost recovery of $13 million and $20 million in costs related to the energy efficiency program for the three and six months ended June 30, 2011 compared to the same periods in 2010 respectively, and $1 million in costsprimarily related to increased recovery of costs on the consumer education programenergy efficiency and smart meter programs as well as administrative costs for the six months ended June 30, 2010, whichGSA and AEPS program that began January 1, 2011. There are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflectedexpenses included in operating and maintenance for regulatory required programs, duringdepreciation and amortization expense.
Pricing
The increase in operating revenues net of purchased power and fuel expense as a result of pricing for the periods.
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the new electric and natural gas distribution rates charged to Threecustomers that became effective January 1, 2011 in accordance with the 2010 PAPUC approved electric and Six Months Ended June 30, 2009.natural gas distribution rate case settlements. See Note 3 – Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for further information.
Transmission
The decreaseincrease in electric operating revenues net of purchased power expense for the three and six months ended June 30, 20102011 compared to the same periods in 20092010 primarily reflected lower gross receipts taxan increase in wholesale transmission revenue dueearned by PECO as a transmission owner for the use of PECO’s transmission facilities in PJM. The rates charged for transmission are based on the prior year’s peak, and the peak in 2010 was higher than in 2009.
Other
For the three and six months ended June 30, 2011 compared to the same periods in 2010, other revenue net of purchased power and fuel expense reflected an increase in revenues associated with volume shifts among customer classes, which resulted in a reduction in the tax rate and decreased late payment fees.
Operating and Maintenance Expense
The increase in operating and maintenance expense for the three and six months ended June 30, 20102011 compared to the same period in 2009,2010, consisted of the following:
Three Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
Increase | Increase | |||||||
(Decrease) | (Decrease) | |||||||
Allowance for uncollectible accounts expense | $ | (7 | ) | $ | (17 | ) | ||
Storm related costs | 11 | 23 | ||||||
Severance | (5 | ) | (5 | ) | ||||
Salaries and wages | 2 | 5 | ||||||
Other | — | (2 | ) | |||||
Increase in operating and maintenance expense | $ | 1 | $ | 4 | ||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Uncollectible accounts expense | $ | 5 | $ | 6 | ||||
Labor, other benefits, contracting and materials | 13 | 25 | ||||||
Pension and non-pension postretirement benefits | (3 | ) | (6 | ) | ||||
Storm-related costs | (10 | ) | (15 | ) | ||||
2010 Non-Cash Charge Resulting from Health Care Legislation | — | (2 | ) | |||||
Other | (1 | ) | 1 | |||||
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Increase in operating and maintenance expense | $ | 4 | $ | 9 | ||||
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Operating and Maintenance for Regulatory Required Programs
Operating and maintenance expenses related to regulatory required programs consisted of costs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenues during the current periods. DuringThe increase in operating and maintenance for regulatory required programs during the three and six months ended June 30, 2011 compared to the same periods in 2010, these expenses consisted of $13primarily reflected $2 million and $20$11 million related to energy efficiency programs, respectively, $2 million and $4 million related to smart meter programs, respectively, and $1 million and $2 million related to consumer education programsGSA administrative costs, respectively. See Note 3 of the Combined Notes to the Consolidated Financial Statements for the six months ended June 30, 2010. PECO did not have operating and maintenance expenses for regulatory required programs for the three and six months ended June 30, 2009.
Depreciation and Amortization Expense
The increasedecrease in depreciation and amortization expense for the three and six months ended June 30, 20102011 compared to the same periods in 20092010 was primarily due to an increasea decrease in scheduled CTC amortization of $37$223 million and $72$444 million, respectively, in accordance with its 1998 Restructuring Settlement.
Taxes Other Than Income
The increasedecrease in taxes other than income for the three and six months ended June 30, 20102011 compared to the same periods in 20092010 was primarily due to an increasedecreased gross receipts tax collections as a result of lower revenues. An equal and offsetting decrease in gross receipts tax expense as a result of higher revenues.
has been reflected in operating revenues during the current periods.
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The increasedecrease in interest expense, net for the three and six months ended June 30, 20102011 compared to the same periods in 20092010 was primarily due to a change in measurement of uncertain tax positions in accordance with accounting guidance. See Note 9guidance in the second quarter of the Combined Notes to the Consolidated Financial Statements for additional information. This increase was partially offset by a decrease in2010 and decreased interest expense due to a reduction of the outstanding debt balance related to PETT as a result of scheduled principal payments.
Other, Net
Other, net for the three and six months ended June 30, 20102011 remained relatively level compared to the same periods in 2009 was primarily due to a decrease2010 with the exception of an increase in interest income related to a change in measurement of uncertain income tax positions.
Effective Income Tax Rate
PECO’s effective income tax rate was 36.2% and 27.9% for the three months ended June 30, 2011 and 2010, respectively, and 32.7% and 31.5% for the three and six months ended June 30, 2010, respectively, as compared to 30.4%2011 and 29.3% for the same periods during 2009,2010, respectively. See Note 98 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.
PECO Electric Operating Statistics and Revenue Detail
Three Months | Weather- | Six Months | Weather- | |||||||||||||||||||||||||||||
Ended June 30, | % | Normal % | Ended June 30, | % | Normal % | |||||||||||||||||||||||||||
Retail Deliveries to customers (in GWhs) | 2010 | 2009 | Change | Change | 2010 | 2009 | Change | Change | ||||||||||||||||||||||||
Retail Delivery and Sales (a) | ||||||||||||||||||||||||||||||||
Residential | 3,118 | 2,764 | 12.8 | % | (2.3 | )% | 6,645 | 6,299 | 5.5 | % | (0.0 | )% | ||||||||||||||||||||
Small commercial & industrial | 2,027 | 2,013 | 0.7 | % | (5.1 | )% | 4,177 | 4,209 | (0.8 | )% | (2.9 | )% | ||||||||||||||||||||
Large commercial & industrial | 4,156 | 3,878 | 7.2 | % | 2.6 | % | 7,950 | 7,669 | 3.7 | % | 1.4 | % | ||||||||||||||||||||
Public authorities & electric railroads | 225 | 222 | 1.4 | % | 1.2 | % | 471 | 469 | 0.4 | % | 0.4 | % | ||||||||||||||||||||
Total Electric Retail | 9,526 | 8,877 | 7.3 | % | (0.7 | )% | 19,243 | 18,646 | 3.2 | % | (0.1 | )% | ||||||||||||||||||||
As of June 30, | ||||||||
Number of Electric Customers | 2010 | 2009 | ||||||
Residential | 1,406,014 | 1,402,515 | ||||||
Small commercial & industrial | 156,423 | 155,970 | ||||||
Large commercial & industrial | 3,093 | 3,089 | ||||||
Public authorities & electric railroads | 1,081 | 1,085 | ||||||
Total | 1,566,611 | 1,562,659 | ||||||
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Three Months Ended June 30, | % Change | Weather - Normal % Change | Six Months Ended June 30, | % Change | Weather - Normal % Change | |||||||||||||||||||||||||||
Retail Deliveries to customers (in GWhs) | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||||||||||
Retail Delivery and Sales(a) | ||||||||||||||||||||||||||||||||
Residential | 3,075 | 3,118 | (1.4 | )% | 3.2 | % | 6,665 | 6,645 | 0.3 | % | 1.7 | % | ||||||||||||||||||||
Small commercial & industrial | 2,026 | 2,027 | (0.0 | )% | 1.7 | % | 4,165 | 4,177 | (0.3 | )% | 0.2 | % | ||||||||||||||||||||
Large commercial & industrial | 3,954 | 4,156 | (4.9 | )% | (3.3 | )% | 7,642 | 7,950 | (3.9 | )% | (3.1 | )% | ||||||||||||||||||||
Public authorities & electric railroads | 229 | 225 | 1.8 | % | 1.8 | % | 471 | 471 | 0.0 | % | 0.0 | % | ||||||||||||||||||||
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Total Electric Retail | 9,284 | 9,526 | (2.5 | )% | (0.1 | )% | 18,943 | 19,243 | (1.6 | )% | (0.6 | )% | ||||||||||||||||||||
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As of June 30, | ||||||||||||||||||||||||||||||||
Number of Electric Customers | 2011 | 2010 | ||||||||||||||||||||||||||||||
Residential | 1,412,692 | 1,406,014 | ||||||||||||||||||||||||||||||
Small commercial & | 156,686 | 156,423 | ||||||||||||||||||||||||||||||
Large commercial & industrial | 3,127 | 3,093 | ||||||||||||||||||||||||||||||
Public authorities & electric railroads | 1,091 | 1,081 | ||||||||||||||||||||||||||||||
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Total | 1,573,596 | 1,566,611 | ||||||||||||||||||||||||||||||
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Three Months Ended June 30, | % Change | Six Months Ended June 30, | % Change | |||||||||||||||||||||
Electric Revenue | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||
Retail Delivery and Sales(a) | ||||||||||||||||||||||||
Residential | $ | 451 | $ | 489 | (7.8 | )% | $ | 944 | $ | 962 | (1.9 | )% | ||||||||||||
Small commercial & industrial | 165 | 271 | (39.1 | )% | 334 | 519 | (35.6 | )% | ||||||||||||||||
Large commercial & industrial | 67 | 337 | (80.1 | )% | 175 | 661 | (73.5 | )% | ||||||||||||||||
Public authorities & electric railroads | 9 | 24 | (62.5 | )% | 20 | 47 | (57.4 | )% | ||||||||||||||||
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Total Retail | 692 | 1,121 | (38.3 | )% | 1,473 | 2,189 | (32.7 | )% | ||||||||||||||||
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Other Revenue | 61 | 59 | 3.4 | % | 126 | 120 | 5.0 | % | ||||||||||||||||
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Total Electric Revenues | $ | 753 | $ | 1,180 | (36.2 | )% | $ | 1,599 | $ | 2,309 | (30.7 | )% | ||||||||||||
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Three Months | Six Months | |||||||||||||||||||||||
Ended June 30, | % | Ended June 30, | % | |||||||||||||||||||||
Electric Revenue | 2010 | 2009 | Change | 2010 | 2009 | Change | ||||||||||||||||||
Retail Delivery and Sales (a) | ||||||||||||||||||||||||
Residential | $ | 489 | $ | 416 | 17.5 | % | $ | 962 | $ | 882 | 9.1 | % | ||||||||||||
Small commercial & industrial | 271 | 260 | 4.2 | % | 519 | 510 | 1.8 | % | ||||||||||||||||
Large commercial & industrial | 337 | 338 | (0.3 | )% | 661 | 657 | 0.6 | % | ||||||||||||||||
Public authorities & electric railroads | 24 | 22 | 9.1 | % | 47 | 45 | 4.4 | % | ||||||||||||||||
Total Retail | 1,121 | 1,036 | 8.2 | % | 2,189 | 2,094 | 4.5 | % | ||||||||||||||||
Other Revenue | 59 | 67 | (11.9 | )% | 120 | 135 | (11.1 | )% | ||||||||||||||||
Total Electric Revenues | $ | 1,180 | $ | 1,103 | 7.0 | % | $ | 2,309 | $ | 2,229 | 3.6 | % | ||||||||||||
(a) | Reflects delivery |
PECO Gas Operating Statistics and Revenue Detail
Three Months | Weather- | Six Months | Weather- | |||||||||||||||||||||||||||||
Ended June 30, | % | Normal % | Ended June 30, | % | Normal % | |||||||||||||||||||||||||||
Deliveries to customers (in mmcf) | 2010 | 2009 | Change | Change | 2010 | 2009 | Change | Change | ||||||||||||||||||||||||
Retail sales | 5,973 | 7,136 | (16.3 | )% | 1.6 | % | 33,557 | 35,750 | (6.1 | )% | 1.4 | % | ||||||||||||||||||||
Transportation and other | 6,540 | 6,105 | 7.1 | % | (3.0 | )% | 15,157 | 13,983 | 8.4 | % | 4.1 | % | ||||||||||||||||||||
Total Gas Deliveries | 12,513 | 13,241 | (5.5 | )% | (0.5 | )% | 48,714 | 49,733 | (2.0 | )% | 2.2 | % | ||||||||||||||||||||
As of June 30, | ||||||||
Number of Gas Customers | 2010 | 2009 | ||||||
Residential | 446,236 | 443,872 | ||||||
Commercial & industrial | 40,944 | 41,008 | ||||||
Total Retail | 487,180 | 484,880 | ||||||
Transportation | 805 | 755 | ||||||
Total | 487,985 | 485,635 | ||||||
Three Months | Six Months | |||||||||||||||||||||||
Ended June 30, | % | Ended June 30, | % | |||||||||||||||||||||
Gas revenue | 2010 | 2009 | Change | 2010 | 2009 | Change | ||||||||||||||||||
Retail Delivery and Sales | ||||||||||||||||||||||||
Retail sales | $ | 81 | $ | 95 | (14.7 | )% | $ | 399 | $ | 475 | (16.0 | )% | ||||||||||||
Transportation and other | 8 | 6 | 33.3 | % | 16 | 14 | 14.3 | % | ||||||||||||||||
Total Gas Deliveries | $ | 89 | $ | 101 | (11.9 | )% | $ | 415 | $ | 489 | (15.1 | )% | ||||||||||||
Three Months Ended June 30, | % Change | Weather - Normal % Change | Six Months Ended June 30, | % Change | Weather - Normal % Change | |||||||||||||||||||||||||||
Deliveries to customers (in mmcf) | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||||||||||
Retail Delivery and Sales(b) | ||||||||||||||||||||||||||||||||
Retail sales | 6,561 | 5,973 | 9.8 | % | (1.3 | )% | 35,295 | 33,557 | 5.2 | % | 0.3 | % | ||||||||||||||||||||
Transportation and other | 6,278 | 6,540 | (4.0 | )% | 2.1 | % | 15,238 | 15,157 | 0.5 | % | 3.3 | % | ||||||||||||||||||||
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Total Gas Deliveries | 12,839 | 12,513 | 2.6 | % | 0.2 | % | 50,533 | 48,714 | 3.7 | % | 1.1 | % | ||||||||||||||||||||
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As of June 30, | ||||||||
Number of Gas Customers | 2011 | 2010 | ||||||
Residential | 449,066 | 446,236 | ||||||
Commercial & industrial | 40,956 | 40,944 | ||||||
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Total Retail | 490,022 | 487,180 | ||||||
Transportation | 864 | 805 | ||||||
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Total | 490,886 | 487,985 | ||||||
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Three Months Ended June 30, | % Change | Six Months Ended June 30, | % Change | |||||||||||||||||||||
Gas revenue | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||
Retail Delivery and Sales(b) | ||||||||||||||||||||||||
Retail sales | $ | 82 | $ | 81 | 1.2 | % | $ | 378 | $ | 399 | (5.3 | )% | ||||||||||||
Transportation and other | 7 | 8 | (12.5 | )% | 19 | 16 | 18.8 | % | ||||||||||||||||
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Total Gas Deliveries | $ | 89 | $ | 89 | 0.0 | % | $ | 397 | $ | 415 | (4.3 | )% | ||||||||||||
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(b) | Reflects delivery revenues and volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed delivery charges. The cost of natural gas is charged to customers purchasing natural gas from PECO. |
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings.
The Registrants’ businesses are capital intensive and require considerable capital resources. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, Exelon, Generation, ComEd and PECO have access to unsecured revolving credit facilities with aggregate bank commitments of $957$500 million, $4.8$5.3 billion, $1 billion and $574$600 million, respectively. Additionally, Generation has access to a supplemental credit facility with an aggregate available commitment of $300 million. The Registrants’ credit facilities extend through October 2012March 2016 for Exelon, Generation and PECO and March 2013 for ComEd. Availability under the supplemental facility extends through December 2015 for $150 million of the $300 million commitment and March 2016 for the remaining $150 million. Exelon, Generation, ComEd and PECO utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for further discussion. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd and PECO operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 57 of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants’ debt and credit agreements.
Cash Flows from Operating Activities
General
Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers. ComEd’s and PECO’s cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, gas distribution services. ComEd’s and PECO’s distribution services are provided to an established and diverse base of retail customers. ComEd’s and PECO’s future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. See Notes 3 and 1213 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.
Pension and OtherNon-Pension Postretirement Benefits
The funded status of the pension and othernon-pension postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. During 2008, Exelon’s unfunded status increased significantly, primarily due to lower than expected 2008 asset returns. The unfunded balance of the plans decreased to $5.83 billion at December 31, 2009, as compared to $6.38 billion at December 31, 2008. While a decrease in discount rates and other factors resulted in an increase in the pension and other postretirement obligation, it was more than offset by the significant increase in asset values during 2009. Additionally, Exelon made a $350 million discretionary contribution to its largest pension plan during 2009.plans. The funded status may changechanges over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.
For financial reporting purposes, the unfunded status of theExelon’s plans is updated annually, at December 31. In order to provide additional information about the potential impact of current financial market conditions on the plans, Exelon has estimated the unfunded status of the pension and postretirement welfare plans at June 30, 20102011 by updating the most significant assumptions impacting theaffecting plan obligations and assets, which are the discount rate and current year’s plan asset investment performance. The discount rates for Exelon’s pension and non-pension postretirement benefit plans were 5.34% and 5.41%, respectively, at June 30, 2011, and 5.26% and 5.30%, respectively, at December 31, 2010. Exelon’s pension and non-pension postretirement benefit plans experienced combined actual asset returns of approximately (2)% and 21%5% for the six months ended June 30, 2010 and year ended December 31, 2009, respectively. Also, the assumed discount rate at June 30, 2010 has decreased 33 basis points since December 31, 2009.
2011.
123
a funded status percentage of $93989% and 43%, respectively. The pension and non-pension postretirement benefit plans amounts have improved by $2,291 million and $329$10 million, respectively, since December 31, 2010 primarily due to the $2.1 billion pension contribution made in January 2011 and the increase in discount rates from December 31, 2009. Exelon has incorporated the estimated reduction in its postretirement welfare obligation resulting from anticipated cost savings related to prescription drugs but has not included any impacts that might arise related to the provisions of the Health Care Reform Acts. 2010.
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under the Employee Retirement Income Security Act (ERISA), as amended, andERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, formanagement of the pension obligation and regulatory implications. Exelon contributed $2.1 billion to its pension plans. Regulatory requirements and the amount deductible for income tax purposes are among the factors considered in determining funding for the other postretirement benefit plans.
Management has estimated its future required pension contributions at June 30, 2010,2011, incorporating the impactupdated projected discount rates and actual census data as of expected 2010 contributions, an assumption for full year 2010 asset returns of 8.5% and a discount rate of 5.5%.January 1, 2011. The estimated pension contributions summarized below include ERISA minimum-required contributions, contributions necessary to avoid benefit restrictions and at-risk status, and payments related to the non-qualified pension plans; these estimates do not include any discretionaryincremental contributions Exelon may elect to make in these future periods or an electionperiods:
2012 | 2013 | 2014 | 2015 | 2016 | Cumulative | |||||||||||||||||||
Estimated pension contributions | $ | 137 | $ | 143 | $ | 122 | $ | 60 | $ | 60 | $ | 522 |
Unlike the qualified pension plans, Exelon’s non-pension postretirement plans are not subject to applyregulatory minimum contribution requirements. Management considers several factors in determining the recent pension funding relief:
2011 | 2012 | 2013 | 2014 | 2015 | Cumulative | |||||||||||||||||||
Estimated contributions | $ | 724 | $ | 809 | $ | 635 | $ | 528 | $ | 320 | $ | 3,016 |
Tax Matters
The Registrants’ future cash flows from operating activities may be affected by the following tax matters:
In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion and CTC positions. Under the terms of the preliminary agreement, Exelon estimates that the IRS will assess tax and interest of approximately $300 million in 2011, and that Exelon will receive additional tax refunds of approximately $270 million between 2011 and 2014. In order to stop additional interest from accruing on the IRS expected assessment, Exelon made a payment in December 2010 to the IRS of $302 million. During 2010, Exelon and IRS Appeals failed to reach a settlement with respect to the like-kind exchange position and the related substantial understatement penalty. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding potential cash flows impacts of a fully successful IRS challenge to Exelon’s like-kind exchange position.
The IRS anticipates issuing guidance in the second half of 2011 on the appropriate tax treatment of repair costs for electric transmission and distribution assets. If the guidance is issued consistent with our expectation and ComEd and PECO choose to change to the newly prescribed method, it would result in an earnings benefit at PECO while Generation will incur additional income tax expense due to a decrease in its manufacturer’s deduction, resulting in an overall minimal effect on consolidated earnings. In addition, this change to the newly prescribed method will result in a cash tax benefit at
ComEd | |||
The Tax Relief Act of 2010, enacted into law on December 17, 2010, includes provisions accelerating the depreciation of certain property for tax purposes. Qualifying property placed into service after September 8, 2010, and before January 1, 2012, is eligible for 100% bonus depreciation. Additionally, qualifying property placed into service during 2012 is eligible for 50% bonus depreciation. These provisions will generate approximately $1 billion of cash for Exelon (approximately $850 million in 2011 and approximately $170 million in 2012). The cash generated is an acceleration of tax benefits that Exelon would have otherwise received over 20 years. Additionally, while the capital additions at ComEd and PECO generally increase future revenue requirements, the bonus depreciation associated with these capital additions will partially mitigate any future rate increases through the ratemaking process. See Note 10 of the Combined Notes to the Financial Statements for further details regarding the use of the cash generated under the Tax Relief Act of 2010.
124Given the current economic environment, state and local governments are facing increasing financial challenges, which may increase the risk of additional income tax levies, property taxes, and other taxes. See Note 8 of the Combined Notes to the Financial Statements for further details regarding the 2011 Illinois State Tax Rate Legislation, which increases the corporate income tax rate in Illinois.
Six Months Ended | ||||||||||||
June 30, | ||||||||||||
2010 | 2009 | Variance | ||||||||||
Net income | $ | 1,194 | $ | 1,369 | $ | (175 | ) | |||||
Add (subtract): | ||||||||||||
Non-cash operating activities(a) | 1,296 | 2,021 | (725 | ) | ||||||||
Pension and non-pension postretirement benefit contributions | (119 | ) | (68 | ) | (51 | ) | ||||||
Income taxes | 661 | (177 | ) | 838 | ||||||||
Changes in working capital and other noncurrent assets and liabilities(b) | (476 | ) | (305 | ) | (171 | ) | ||||||
Option premiums (paid) received, net | (15 | ) | (39 | ) | 24 | |||||||
Counterparty collateral received (posted), net | (172 | ) | 246 | (418 | ) | |||||||
Net cash flows provided by operations | $ | 2,369 | $ | 3,047 | $ | (678 | ) | |||||
Six Months Ended June 30, | ||||||||||||
2011 | 2010 | Variance | ||||||||||
Net income | $ | 1,288 | $ | 1,194 | $ | 94 | ||||||
Add (subtract): | ||||||||||||
Non-cash operating activities(a) | 2,295 | 1,296 | 999 | |||||||||
Pension and non-pension postretirement benefit contributions | (2,089 | ) | (119 | ) | (1,970 | ) | ||||||
Income taxes | 691 | 661 | 30 | |||||||||
Changes in working capital and other noncurrent assets and liabilities(b) | (716 | ) | (476 | ) | (240 | ) | ||||||
Option premiums received (paid), net | 38 | (15 | ) | 53 | ||||||||
Counterparty collateral posted, net | (494 | ) | (172 | ) | (322 | ) | ||||||
Net cash flows provided by operations | $ | 1,013 | $ | 2,369 | $ | (1,356) | ||||||
(a) | Represents depreciation, amortization and accretion, | |
(b) | Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt. |
Cash flows provided by operations for the six months ended June 30, 20102011 and 20092010 by Registrant were as follows:
Six Months Ended | ||||||||
June 30, | ||||||||
2010 | 2009 | |||||||
Exelon | $ | 2,369 | $ | 3,047 | ||||
Generation | 1,453 | 2,014 | ||||||
ComEd | 404 | 581 | ||||||
PECO | 555 | 584 |
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
Exelon | $ | 1,013 | $ | 2,369 | ||||
Generation | 1,076 | 1,453 | ||||||
ComEd | 71 | 404 | ||||||
PECO | 359 | 555 |
Changes in Exelon’s, Generation’s, ComEd’s and PECO’s cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business. In addition, significant operating cash flow impacts for the Registrants for the six months ended June 30, 20102011 and 20092010 were as follows:
Generation
125
During the six months ended June 30, 2011 and 2010, Generation had net collections (payments) of approximately $38 million and $(15) million, respectively, related to the purchase and sales of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.
ComEd
During the six months ended June 30, 2011 and 2010, ComEd’s payables to Generation for energy purchases related to its supplier forward contract, ICC-approved RFP contracts and financial swap contract decreased by $80$15 million and $68$80 million, respectively. During the six months ended June 30, 20102011 and 2009,2010, ComEd’s payables to other energy suppliers for energy purchases (decreased) increased (decreased) by $(6) million and $18 million, and $(39) million, respectively.
During the six months ended June 30, 2010,2011, ComEd posted $120received $31 million of cash collateral returned from PJM due to seasonal variations in its energy transmission activity levels. As of June 30, 2011, ComEd had $122 million of collateral remaining at PJM. Prior
ComEd’s working capital, defined as current assets less current liabilities, is in a net deficit position primarily due to continued capital expenditures to improve and expand its service system as well as maturing long-term debt. ComEd intends to refinance the second quarter of 2010, ComEd used letters of credit to cover all PJM collateral requirements.maturing long-term debt during 2011.
PECO
During the six months ended June 30, 20102011 and 2009,2010, PECO’s payables to Generation under the PPAfor energy purchases (decreased) increased by $17$(206) million and $55$17 million, respectively. During the six months ended June 30, 20102011 and 2009,2010, PECO’s payables to other energy suppliers for energy purchases increased (decreased) by $108 million and $3 million, and $(42) million, respectively.
During the six months ended June 30, 20102011 and 2009,2010, PECO’s prepaid utility taxes increased by $112$90 million and $129$112 million, respectively, primarily due to the Pennsylvania Gross Receipts Tax prepayment in March of each year.
Cash Flows from Investing Activities
Cash flows used in investing activities for the six months ended June 30, 20102011 and 20092010 by Registrant were as follows:
Six Months Ended | ||||||||
June 30, | ||||||||
2010 | 2009 | |||||||
Exelon | $ | (1,658 | ) | $ | (1,546 | ) | ||
Generation | (1,075 | ) | (926 | ) | ||||
ComEd | (437 | ) | (421 | ) | ||||
PECO | (222 | ) | (250 | ) |
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
Exelon | $ | (2,074 | ) | $ | (1,658 | ) | ||
Generation | (1,388 | ) | (1,075 | ) | ||||
ComEd | (473 | ) | (437 | ) | ||||
PECO | (371 | ) | (222 | ) |
Capital expenditures by Registrant for the six months ended June 30, 2011 and 2010 and projected amounts for the full year 20102011 are as follows:
Six Months Ended | Projected | |||||||
June 30, 2010 | 2010 | |||||||
Generation (a) | $ | 982 | $ | 1,975 | ||||
ComEd | 453 | 940 | ||||||
PECO | 218 | 495 | ||||||
Other (b)(c) | (69 | ) | 30 | |||||
Exelon | $ | 1,584 | $ | 3,440 | ||||
Projected Full Year | Six Months Ended June 30, | |||||||||||
2011 | 2011 | 2010 | ||||||||||
Generation(a) | $ | 2,510 | $ | 1,270 | $ | 982 | ||||||
ComEd | 1,015 | 495 | 453 | |||||||||
PECO | 450 | 209 | 218 | |||||||||
Other(b) | 56 | 11 | (69 | ) | ||||||||
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Exelon | $ | 4,031 | $ | 1,985 | $ | 1,584 | ||||||
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(a) | Includes nuclear fuel. | |
(b) | Other primarily consists of corporate operations and BSC. | |
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Generation.Generation
Approximately 43%42% of the projected 20102011 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts primarily reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Included in the projected 20102011 capital expenditures are a portion of the costs of a series of planned power uprates across the company’sGeneration’s nuclear fleet. See “EXELON CORPORATION — Executive Overview,” for more information on nuclear uprates.
ComEd and PECO.PECO
Approximately 75%81% and 82%72% of the projected 20102011 capital expenditures at ComEd and PECO, respectively, are for continuing projects to maintain and improve company operations, including enhancing reliability and adding capacity to the transmission and distribution systems.systems such as PECO’s transmission system reliability upgrades required by PJM related to Generation’s plan retirements. The remaining amounts are for capital additions to support new business and customer growth, which for PECO includes capital expenditures related to its smart meter program and AMISGIG project, net of DOE expected reimbursements. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.
On November 30, 2010, NERC provided guidance to transmission owners that will require ComEd and Smart Grid technologies.PECO to perform assessments of all their transmission lines, with the highest priority lines assessed by December 31, 2011, medium priority lines by December 31, 2012, and the lowest priority lines by December 31, 2013. ComEd and PECO may be required to incur incremental capital expenditures, which may be significant at ComEd, associated with this guidance upon completion of the assessments. Specific projects and expenditures will not be identified until the assessments are completed. ComEd and PECO are each continuing to evaluate their total capital spending requirements. ComEd and PECO anticipate that they will fund their capital expenditures with internally generated funds and borrowings.
Cash Flows from Financing Activities
Cash flows used inprovided by (used in) financing activities for the six months ended June 30, 20102011 and 20092010 by Registrant were as follows:
Six Months Ended | ||||||||
June 30, | ||||||||
2010 | 2009 | |||||||
Exelon | $ | (1,553 | ) | $ | (934 | ) | ||
Generation | (629 | ) | (674 | ) | ||||
ComEd | (17 | ) | (152 | ) | ||||
PECO | (429 | ) | (173 | ) |
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
Exelon | $ | 11 | $ | (1,553 | ) | |||
Generation | (35 | ) | (629 | ) | ||||
ComEd | 446 | (17 | ) | |||||
PECO | (191 | ) | (429 | ) |
Debt.Debt
See Note 57 of the Combined Notes to the Consolidated Financial Statements for further details of the Registrants’ debt issuances and retirements.
Dividends.Dividends
Cash dividend payments and distributions during the six months ended June 30, 20102011 and 20092010 by Registrant were as follows:
Six Months Ended | ||||||||
June 30, | ||||||||
2010 | 2009 | |||||||
Exelon | $ | 694 | $ | 692 | ||||
Generation | 417 | 675 | ||||||
ComEd | 150 | 120 | ||||||
PECO | 117 | 156 |
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
Exelon | $ | 695 | $ | 694 | ||||
Generation | — | 417 | ||||||
ComEd | 150 | 150 | ||||||
PECO | 186 | 117 |
Short-Term Borrowings.Borrowings
During the six months ended June 30, 2011, Exelon issued $140 million of commercial paper. During the six months ended June 30, 2010, ComEd repaid $155 million of outstanding borrowings under its credit agreement and issued $289 million of commercial paper.
Contributions from Parent/Member
During the six months ended June 30, 2009, Exelon and2011, there were no contributions from Parent/Member (Exelon). As of December 31, 2010, the parent receivable at PECO repaid $151 million and $95 million of commercial paper, respectively.was retired. During the six months ended June 30, 2009, ComEd repaid $15 million of outstanding borrowings under its credit agreement.
Other
For the six months ended June 30, 2010 and 2009, respectively,2011, other financing activities primarily consists of expenses paid related to reduce the receivable from parent.
replacement of the Registrants’ credit facilities. See Note 7 of the Combined Notes to Consolidated Financial Statements for additional information.
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The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $7.4$7.7 billion in aggregate total commitments of which $6.9$7.2 billion was available as of June 30, 2010,2011, and of which no financial institution has
more than 9% of the aggregate commitments. Exelon, Generation, ComEd and PECO had access to the commercial paper market during the second quarter of 2010. Due to an upgrade in ComEd’s commercial paper rating last year and improvements in the commercial paper market, ComEd has been able to rely on the commercial paper market as a source of liquidity.2011. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A Risk Factors of Exelon’s 20092010 Annual Report on Form 10-K for further information regarding the effects of a uncertainty in the capital and credit markets or significant bank failures.
The Registrants believe their cash flow from operations, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of June 30, 2010,2011, it would have been required to provide incremental collateral of approximately $1,206$1,238 million, which is well within its current available credit facility capacities of approximately $4.6$5.5 billion. The $1,206$1,238 million includes $994$1,031 million of collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payable and receivables, net of the contractual right of offset under master netting agreements and $212$207 million of financial assurances that Generation would be required to provide Nuclear Electric Insurance Limited related to annual retrospective premium obligations. If ComEd lost its investment grade credit rating as of June 30, 2010,2011, it would have been required to provide incremental collateral of approximately $233 million, which is well within its current available credit facility capacity of approximately $515$805 million, which takes into account commercial paper borrowings as of June 30, 2010.2011. If PECO lost its investment grade credit rating as of June 30, 2010,2011, it would have been required to provide collateral of $6$3 million pursuant to PJM’s credit policy and could have been required to provide collateral of approximately $46$40 million related to its natural gas procurement contracts, which, in the aggregate, is well within PECO’s current available credit facility capacity of $571$599 million.
Exelon Credit Facilities
Exelon meets itsand ComEd meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool, and ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 57 of the Combined Notes to the Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.
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Average Interest Rate on | ||||||||||||
Commercial Paper | ||||||||||||
Outstanding | Borrowings for the six | |||||||||||
Commercial Paper at | months ended | |||||||||||
Commercial Paper Issuer | Maximum Program Size(a) | June 30, 2010 | June 30, 2010 | |||||||||
Exelon Corporate | $ | 957 | $ | — | — | |||||||
Generation | 4,834 | — | — | |||||||||
ComEd | 1,000 | 289 | 0.74 | % | ||||||||
PECO | 574 | — | — |
Commercial Paper Programs | ||||||||||||
Commercial Paper Issuer | Maximum Program Size(a) | Outstanding Commercial Paper at June 30, 2011 | Average Interest Rate on Commercial Paper Borrowings for the six months ended June 30, 2011 | |||||||||
Exelon Corporate | $ | 500 | $ | 140 | 0.36 | % | ||||||
Generation | 5,600 | — | 0.32 | % | ||||||||
ComEd | 1,000 | — | 0.72 | % | ||||||||
PECO | 600 | — | — |
(a) | Equals aggregate bank commitments under revolving credit agreements and bilateral credit agreements. See discussion and table below for items affecting effective program size. |
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have revolving credit facilities in place at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s
credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceeding the available capacity under its credit agreement.
Available Capacity at June 30, 2010 | Average Interest Rate on | |||||||||||||||||||||||
Outstanding | To Support | Facility Borrowings for | ||||||||||||||||||||||
Aggregate Bank | Facility | Letters of | Additional | six months ended | ||||||||||||||||||||
Borrower | Commitment(a) | Draws | Credit | Actual | Commercial Paper | June 30, 2010 | ||||||||||||||||||
Exelon Corporate | $ | 957 | $ | — | $ | 5 | $ | 952 | $ | 952 | — | |||||||||||||
Generation | 4,834 | — | 231 | 4,603 | 4,603 | — | ||||||||||||||||||
ComEd | 1,000 | — | 196 | 804 | 515 | 0.61 | % | |||||||||||||||||
PECO | 574 | — | 3 | 571 | 571 | — |
Credit Agreements | ||||||||||||||||||||||||||
Available Capacity at June 30, 2011 | Average Interest Rate on Facility Borrowings for six months ended June 30, 2011 | |||||||||||||||||||||||||
Borrower | Facility Type | Aggregate Bank Commitment(a) | Facility Draws | Outstanding Letters of Credit | Actual | To Support Additional Commercial Paper | ||||||||||||||||||||
Exelon Corporate | Syndicated Revolver | $ | 500 | $ | — | | $ | 7 | $ | 493 | $ | 353 | — | |||||||||||||
Generation | Syndicated Revolver | 5,300 | — | 7 | 5,293 | 5,293 | — | |||||||||||||||||||
Generation | Bilateral | 300 | — | 114 | 186 | 186 | — | |||||||||||||||||||
ComEd | Syndicated Revolver | 1,000 | — | 195 | 805 | 805 | — | |||||||||||||||||||
PECO | Syndicated Revolver | 600 | — | 1 | 599 | 599 | — |
(a) | Excludes |
Borrowings under eachthe revolving credit agreement mayagreements bear interest at a rate that floats daily based upon aeither the prime rate or at a fixed rate fixed for a specified interest period based upon a LIBOR-based rate. Under theThe Exelon, Generation and PECO agreements an adderprovide for adders of up to 6585 basis points may be addedfor prime-based borrowings and adders of up to the185 basis points for LIBOR-based rate,borrowings, based upon the credit rating of the borrower. At June 30, 2011, Exelon, Generation and PECO adders were 30, 30 and 10 basis points, respectively, for prime-based borrowings and 130, 130 and 110 basis points, respectively, for LIBOR-based borrowings. Under the ComEd agreement, adders of up to 137.5 basis points for prime-based borrowings and 237.5 basis points for LIBOR-based borrowings may be added based upon ComEd’s credit rating. As ofAt June 30, 2010, ComEd did not have any2011, ComEd’s adder was 87.5 basis points for prime based borrowings under itsand 187.5 basis points for LIBOR-based borrowings.
Under Generation’s bilateral credit facility.
Each credit agreement requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The interest coverage ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and interest on nonrecourse debt. The following table summarizes the minimum thresholds reflected in the credit agreements for the six months ended June 30, 2010:
Exelon | Generation | ComEd | PECO | |||||||||||||
Credit agreement threshold | 2.50 to 1 | 3.00 to 1 | 2.00 to 1 | 2.00 to 1 |
At June 30, 2010,2011, the interest coverage ratios at the Registrants were as follows:
Exelon | Generation | ComEd | PECO | |||||||||||||
Interest coverage ratio | 10.45 | 27.48 | 3.97 | 2.26 |
Exelon | Generation | ComEd | PECO | |||||||||||||
Interest coverage ratio | 16.77 | 28.91 | 6.82 | 9.42 |
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principal, premium or interest on any indebtedness having a principal amount in excess of $100 million in the aggregate by Generation (including Generation’s credit facility) will constitute an event of default under the Exelon credit facility.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. Refer to Note 6 of the Combined Notes to the Consolidated Financial Statements for additional information on collateral provisions.
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To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant during the six months ended June 30, 2010 are presented in the following table2011, in addition to the net contribution or borrowing as of June 30, 2010:
June 30, 2010 | ||||||||||||
Maximum | Maximum | Contributed | ||||||||||
Contributed | Borrowed | (Borrowed) | ||||||||||
BSC | $ | — | $ | 67 | $ | — | ||||||
Exelon Corporate | 67 | N/A | — |
Maximum Contributed | Maximum Borrowed | Contributed (Borrowed) | ||||||||||
Generation | $ | — | $ | 335 | $ | — | ||||||
PECO | 465 | — | 171 | |||||||||
BSC | — | 220 | (171 | ) | ||||||||
Exelon Corporate | 261 | N/A | — |
Variable-Rate Debt
See Note 57 of the Combined Notes to the Consolidated Financial Statements for further discussion regarding the Registrants’ variable rate debt.
Investments in Nuclear Decommissioning Trust Funds
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the values of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. With regards to equity securities, Generation’s investment policy establishes limits on the concentration of equity holdings in any one company and also in any one industry. With regards to its fixed-income securities, Generation’s investment policy limits the concentrations of the types of bonds that may be purchased for the trust funds and also requires a minimum percentage of the
portfolio to have investment grade ratings (minimum credit quality ratings of “Baa3” by Moody’s, “BBB-” by S&P and “BBB-” by Fitch Ratings) while requiring that the overall portfolio maintain a minimum credit quality rating of “A2”. See Note 109 of the Combined Notes to the Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.
Shelf Registration Statements
Each of the Registrants each havehas a current shelf registration statementsstatement effective with the SEC that provide for the sale of unspecified amounts of securities. The ability of each Registrant to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the company, its securities ratings and market conditions.
Regulatory Authorizations
As of June 30, 2010,2011, ComEd had $789$577 million available in long-term debt refinancing authority and $1,407$520 million available in new money long-term debt financing authority from the ICC, and PECO had $1.9 billion available in long-term debt financing authority from the PAPUC.
As of June 30, 2010,2011, ComEd and PECO had short-term financing authority from FERC, thatwhich expires on December 31, 2011, of $2.5 billion and $1.5 billion, respectively.
ComEd and PECO plan to file for renewal of this short-term financing authority in the second half of 2011.
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Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 1213 of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants’ commitments.
Generation, ComEd and PECO have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 of the Combined Notes to Consolidated Financial Statements for further information.
General
Generation operates in three segments: Mid-Atlantic, Midwest, and South.South and West. The operations of all three segments consist of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations. These segments are discussed in further detail in “EXELON CORPORATION — General” of this Form 10-Q.
Executive Overview
A discussion of items pertinent to Generation’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.
Results of Operations
A discussion of items pertinent to Generation’s results of operations for the three months ended June 30, 20102011 compared to the three months ended June 30, 20092010 and the six months ended June 30, 2011 compared to the six months ended June 30, 2010 is set forth under “Results of Operations — Generation” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.
Liquidity and Capital Resources
Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to revolving credit facilities of $4.8$5.6 billion that Generation currently utilizes to support its commercial paper program and to issue letters of credit.
See the “EXELON CORPORATION—CORPORATION — Liquidity and Capital Resources” of this Form 10-Q for further discussion.
Capital resources are used primarily to fund Generation’s capital requirements, including construction, retirement of debt, the payment of distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could require external financing or borrowings or capital contributions from Exelon.
Cash Flows from Operating Activities
A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
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A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Financing Activities
A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Credit Matters
A discussion of items pertinent to Generation’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of items pertinent to Generation’s contractual obligations and off-balance sheet arrangements is set forth under “Other Purchase Obligations” in Note 1213 of the Combined Notes to Consolidated Financial Statements.
General
ComEd operates in a single operating segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago.
Executive Overview
A discussion of items pertinent to ComEd’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.
Results of Operations
A discussion of items pertinent to ComEd’s results of operations for the three months ended June 30, 20102011 compared to the three months ended June 30, 20092010, and the six months ended June 30, 20102011 compared to the six months ended June 30, 20092010, is set forth under “Results of Operations — ComEd” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.
Liquidity and Capital Resources
ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, and credit facility borrowings.borrowings and the issuance of First Mortgage Bonds. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where ComEd no longer has access to the capital markets at reasonable terms, ComEd has access to its revolving credit facility. At June 30, 2010,2011, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.
See the “EXELON CORPORATION — Liquidity and Capital Resources” and Note 57 of the Combined Notes to the Financial Statements of this Form 10-Q for further discussion.
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Cash Flows from Operating Activities
A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Investing Activities
A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Financing Activities
A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Credit Matters
A discussion of items pertinent to ComEd’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of items pertinent to ComEd’s contractual obligations and off-balance sheet arrangements is set forth under “Other Purchase Obligations” in Note 1213 of the Combined Notes to Consolidated Financial Statements.
General
PECO operates in two business segments that are aggregated into one reportable segment, and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in Pennsylvania in the counties surrounding the City of Philadelphia.
Executive Overview
A discussion of items pertinent to PECO’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.
Results of Operations
A discussion of items pertinent to PECO’s results of operations for the three months ended June 30, 20102011 compared to three months ended June 30, 20092010 and six months ended June 30, 20102011 compared to six months ended June 30, 20092010 is set forth under “Results of Operations — PECO” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.
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PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations, and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, accounts receivable agreement or participation in the intercompany money pool. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility. At June 30, 2010,2011, PECO had access to a revolving credit facility with aggregate bank commitments of $574$600 million.
See “EXELON CORPORATION—CORPORATION — Liquidity and Capital Resources” of this Form 10-Q for further discussion.
Capital resources are used primarily to fund PECO’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Investing Activities
A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Financing Activities
A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Credit Matters
A discussion of items pertinent to PECO’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of items pertinent to PECO’s contractual obligations and off-balance sheet arrangements is set forth under “Other Purchase Obligations” in Note 1213 of the Combined Notes to Consolidated Financial Statements.
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The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The RMC reports to the Exelon Board of Directors on the scope of the risk management activities. The following discussion serves as an update to Item 7A-Quantitative and Qualitative Disclosures about Market Risk of the Registrants’ 20092010 Annual Report on Form 10-K incorporated herein by reference.
Commodity Price Risk (Exelon, Generation, ComEd and PECO)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Exelon seeks to mitigate its commodity price risk through the purchase and sale of electricity, fossil fuel, and other commodities.
Generation
Normal Operations and Hedging Activities.Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including ComEd’s and PECO’s retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as financial derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges, will occur during 2010 through 2012 andincluding the ComEd financial swap contract, will occur during 20102011 through 2013. Generation’s energy contracts are accounted for under the accounting guidance for derivatives as further discussed in Note 6 of the Combined Notes to Consolidated Financial Statements.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over the three years leading to the spot market. As of June 30, 2010,2011, the percentage of expected generation hedged was 96%-99%95%-98%, 86%-89%82%-85%, and 57%-60%49%-52% for 2010, 2011, 2012 and 2012,2013, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s non-trading portfolio associated with a $5 reduction in the annual average Ni-Hub and PJM-West around-the-clock energy price based on June 30, 20102011 market conditions and hedged position would be a decrease in pre-tax net income of approximately $9$6 million, $92$130 million and $333$398 million, respectively, for 2010, 2011, 2012 and 2012.2013. Power prices sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.
Proprietary Trading Activities.Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure and is subject to limits established by Exelon’s RMC. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss and Value-at-Risk (VaR) limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities, which included physical volumes of 1,496 GWhs and 2,829 GWhs for the three and six months ended June 30, 2011, respectively, and 889 GWhs and 1,808 GWhs for the three and six months ended June 30, 2010, respectively, and 2,003 GWhs and 4,334 GWhs for the three and six months ended June 30, 2009, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall revenue from energy marketing activities. Trading portfolio activity for the six months ended June 30, 20102011 resulted in pre-tax gains of $25$22 million due to net mark-to-market gains of $14$7 million and realized gains of $11$15 million. Generation uses a 95% confidence interval, one day holding period, one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $120,000$130,000 of exposure over the last 18 months. Because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin from continuing operations for the six months ended June 30, 20102011 of $3,276$3,374 million, Generation has not segregated proprietary trading activity in the following tables.
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ComEd
The five-year financial swap contract between Generation and ComEd was deemed prudent by the Illinois Settlement Legislation, thereby ensuring that ComEd will be entitled to receive full cost recovery in rates.
ComEd’s RFP contracts are deemed to be derivatives that qualify for the normal purchasepurchases and normal sales exceptionscope exceptions under derivative accounting guidance. ComEd does not enter into derivatives for speculative or proprietary trading purposes.
On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. Delivery under these contracts begins in June 2012. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. For additional information on these contracts, see Note 6 of the Combined Notes to Consolidated Financial Statements.
PECO
PECO have entered into a long-term full-requirements PPA under which PECO obtains all of its electric supply from Generation through 2010. The PPA is not considered a derivative. Pursuant to PECO’s PAPUC-approved DSP Program, PECO began to procureprocures electric supply for default service customers in June 2009 for the post-transition period beginning on January 1, 2011 through block contracts and full requirements fixed price contracts.contracts pursuant to PECO’s PAPUC-approved DSP Program. PECO’s full requirements fixed price contracts and block contracts that are considered derivatives qualify for the normal purchases and normal sales scope exception.exception under current derivative authoritative guidance. Under the DSP Program, PECO is permitted to recover its electricity procurement costs from retail customers without mark-up.
PECO has also entered into derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its long-term price risk in the natural gas market. PECO does not enter into derivatives for speculative or proprietary trading purposes. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.
PECO does not enter into derivatives for speculative or proprietary trading purposes.
For additional information on these contracts, see Note 6 of the Combined Notes to Consolidated Financial Statements.
Trading and Non-Trading Marketing Activities.Activities
The following detailed presentation of Exelon’s, Generation’s, ComEd’s and PECO’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).
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Intercompany | ||||||||||||||||||||
Generation | ComEd | PECO | Eliminations (e) | Exelon | ||||||||||||||||
Total mark-to-market energy contract net assets (liabilities) at December 31, 2009(a) | $ | 1,769 | $ | (971 | ) | $ | (4 | ) | $ | — | $ | 794 | ||||||||
Total change in fair value during 2010 of contracts recorded in result of operations | 280 | — | — | — | 280 | |||||||||||||||
Reclassification to realized at settlement of contracts recorded in results of operations | (157 | ) | — | — | — | (157 | ) | |||||||||||||
Reclassification to realized at settlement from accumulated OCI(b) | (543 | ) | — | — | 160 | (383 | ) | |||||||||||||
Effective portion of changes in fair value—recorded in OCI (c) (f) | 547 | — | — | (202 | ) | 345 | ||||||||||||||
Changes in fair value—energy derivatives (d) | — | (39 | ) | (5 | ) | 42 | (2 | ) | ||||||||||||
Changes in collateral | 49 | — | — | — | 49 | |||||||||||||||
Changes in net option premium paid/(received) | 15 | — | — | — | 15 | |||||||||||||||
Other income statement reclassifications (g) | 36 | — | — | — | 36 | |||||||||||||||
Other balance sheet reclassifications | (3 | ) | — | — | — | (3 | ) | |||||||||||||
Total mark-to-market energy contract net assets (liabilities) at June 30, 2010(a) | $ | 1,993 | $ | (1,010 | ) | $ | (9 | ) | $ | — | $ | 974 | ||||||||
Generation | ComEd | PECO | Intercompany Eliminations(e) | Exelon | ||||||||||||||||
Total mark-to-market energy contract net assets (liabilities) at December 31, 2010(a) | $ | 1,803 | $ | (971 | ) | $ | (9 | ) | $ | — | $ | 823 | ||||||||
Total change in fair value during 2011 of contracts recorded in result of operations | 12 | — | — | — | 12 | |||||||||||||||
Reclassification to realized at settlement of contracts recorded in results of operations | (285 | ) | — | — | — | (285 | ) | |||||||||||||
Ineffective portion recognized in income | 8 | — | — | — | 8 | |||||||||||||||
Reclassification to realized at settlement from accumulated OCI(b) | (454 | ) | — | — | 223 | (231 | ) | |||||||||||||
Effective portion of changes in fair value — recorded in OCI(c)(f) | (81 | ) | — | — | (2 | ) | (83 | ) | ||||||||||||
Changes in fair value — energy derivatives(d) | — | 183 | 5 | (221 | ) | (33 | ) | |||||||||||||
Changes in collateral | 526 | — | — | — | 526 | |||||||||||||||
Changes in net option premium paid/(received) | (38 | ) | — | — | — | (38 | ) | |||||||||||||
Other income statement reclassifications(g) | (68 | ) | — | — | — | (68 | ) | |||||||||||||
Other balance sheet reclassifications | 1 | — | — | — | 1 | |||||||||||||||
Total mark-to-market energy contract net assets (liabilities) at June 30, 2011(a) | $ | 1,424 | $ | (788 | ) | $ | (4 | ) | $ | — | $ | 632 | ||||||||
(a) | Amounts are shown net of collateral paid to and received from counterparties. | |
(b) | For Generation, includes |
(c) | For Generation, includes $2 million of gains related to the | |
(d) | For ComEd and PECO, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of June 30, | |
(e) | Amounts related to the five-year financial swap between Generation and ComEd and the block contracts between Generation and PECO are eliminated in consolidation. | |
(f) | For Generation, includes $8 million of changes in cash flow hedge ineffectiveness, | |
(g) | Includes |
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The following table present maturity and source of fair value of the Registrants mark-to-market energy contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities). Second, the tables show the maturity, by year, of the Registrants’ energy contract net assets (liabilities), giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 45 of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Exelon
Maturities Within | ||||||||||||||||||||||||||||
2015 and | Total Fair | |||||||||||||||||||||||||||
2010 | 2011 | 2012 | 2013 | 2014 | Beyond | Value | ||||||||||||||||||||||
Normal Operations, qualifying cash flow hedge contracts (a)(c): | ||||||||||||||||||||||||||||
Prices provided by external sources | $ | 215 | $ | 319 | $ | 86 | $ | 32 | $ | 2 | $ | — | $ | 654 | ||||||||||||||
Prices based on model or other valuation methods | — | (3 | ) | — | 1 | — | — | (2 | ) | |||||||||||||||||||
Total | $ | 215 | $ | 316 | $ | 86 | $ | 33 | $ | 2 | $ | — | $ | 652 | ||||||||||||||
Normal Operations, other derivative contracts (b)(c): | ||||||||||||||||||||||||||||
Actively quoted prices | $ | (2 | ) | $ | (1 | ) | $ | — | $ | — | $ | — | $ | — | $ | (3 | ) | |||||||||||
Prices provided by external sources | (125 | ) | 219 | 110 | 35 | 17 | — | 256 | ||||||||||||||||||||
Prices based on model or other valuation methods | 3 | 39 | 7 | 18 | 2 | — | 69 | |||||||||||||||||||||
Total | $ | (124 | ) | $ | 257 | $ | 117 | $ | 53 | $ | 19 | $ | — | $ | 322 | |||||||||||||
Maturities Within | ||||||||||||||||||||||||||||
2011 | 2012 | 2013 | 2014 | 2015 | 2016 and Beyond | Total Fair Value | ||||||||||||||||||||||
Normal Operations, qualifying cash flow hedge contracts(a)(c): | ||||||||||||||||||||||||||||
Prices provided by external sources | $ | 180 | $ | 77 | $ | 47 | $ | 1 | $ | — | $ | — | $ | 305 | ||||||||||||||
Prices based on model or other valuation methods | (1 | ) | — | 1 | (11 | ) | — | — | (11 | ) | ||||||||||||||||||
Total | $ | 179 | $ | 77 | $ | 48 | $ | (10 | ) | $ | — | $ | — | $ | 294 | |||||||||||||
Normal Operations, other derivative contracts(b)(c): | ||||||||||||||||||||||||||||
Actively quoted prices | $ | — | $ | (1 | ) | $ | — | $ | — | $ | — | $ | — | $ | (1 | ) | ||||||||||||
Prices provided by external sources | 110 | 99 | 90 | 43 | 2 | — | 344 | |||||||||||||||||||||
Prices based on model or other valuation methods(d) | 10 | 7 | (15 | ) | (8 | ) | (9 | ) | 10 | (5 | ) | |||||||||||||||||
Total | $ | 120 | $ | 105 | $ | 75 | $ | 35 | $ | (7 | ) | $ | 10 | $ | 338 | |||||||||||||
(a) | Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in OCI. | |
(b) | Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts that do not qualify as cash flow hedges are recorded in results of operations. | |
(c) | Amounts are shown net of collateral paid to and received from counterparties of |
(d) | Includes ComEd’s net assets associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Generation
Maturities Within | ||||||||||||||||||||||||||||
2015 and | Total Fair | |||||||||||||||||||||||||||
2010 | 2011 | 2012 | 2013 | 2014 | Beyond | Value | ||||||||||||||||||||||
Normal Operations, qualifying cash flow hedge contracts(a)(c): | ||||||||||||||||||||||||||||
Prices provided by external sources | $ | 215 | $ | 319 | $ | 86 | $ | 32 | $ | 2 | $ | — | $ | 654 | ||||||||||||||
Prices based on model or other valuation methods | 190 | 387 | 331 | 109 | — | — | 1,017 | |||||||||||||||||||||
Total | $ | 405 | $ | 706 | $ | 417 | $ | 141 | $ | 2 | $ | — | $ | 1,671 | ||||||||||||||
Normal Operations, other derivative contracts (b)(c): | ||||||||||||||||||||||||||||
Actively quoted prices | $ | (2 | ) | $ | (1 | ) | $ | — | $ | — | $ | — | $ | — | $ | (3 | ) | |||||||||||
Prices provided by external sources | (125 | ) | 219 | 110 | 35 | 17 | — | 256 | ||||||||||||||||||||
Prices based on model or other valuation methods | 3 | 39 | 7 | 18 | 2 | — | 69 | |||||||||||||||||||||
Total | $ | (124 | ) | $ | 257 | $ | 117 | $ | 53 | $ | 19 | $ | — | $ | 322 | |||||||||||||
Maturities Within | ||||||||||||||||||||||||||||
2011 | 2012 | 2013 | 2014 | 2015 | 2016 and Beyond | Total Fair Value | ||||||||||||||||||||||
Normal Operations, qualifying cash flow hedge contracts(a)(c): | ||||||||||||||||||||||||||||
Prices provided by external sources | $ | 180 | $ | 77 | $ | 47 | $ | 1 | $ | — | $ | — | $ | 305 | ||||||||||||||
Prices based on model or other valuation methods | 220 | 395 | 144 | (11 | ) | — | — | 748 | ||||||||||||||||||||
Total | $ | 400 | $ | 472 | $ | 191 | $ | (10 | ) | $ | — | $ | — | $ | 1,053 | |||||||||||||
Normal Operations, other derivative contracts(b)(c): | ||||||||||||||||||||||||||||
Actively quoted prices | $ | — | $ | (1 | ) | $ | — | $ | — | $ | — | $ | — | $ | (1 | ) | ||||||||||||
Prices provided by external sources | 110 | 99 | 90 | 43 | 2 | — | 344 | |||||||||||||||||||||
Prices based on model or other valuation methods | 12 | 15 | (1 | ) | 2 | (1 | ) | 1 | 28 | |||||||||||||||||||
Total | $ | 122 | $ | 113 | $ | 89 | $ | 45 | $ | 1 | $ | 1 | $ | 371 | ||||||||||||||
(a) | Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in OCI. Amounts include a | |
(b) | Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts that do not qualify as cash flow hedges are recorded in results of operations. | |
(c) | Amounts are shown net of collateral paid to and received from counterparties of |
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Maturities Within | ||||||||||||||||||||||||
2010 | 2011 | 2012 | 2013 | 2014 | Total Fair Value | |||||||||||||||||||
Prices based on model or other valuation methods(a) | $ | (190 | ) | $ | (381 | ) | $ | (331 | ) | $ | (108 | ) | $ | — | $ | (1,010 | ) |
Maturities Within | ||||||||||||||||||||||||||||
2011 | 2012 | 2013 | 2014 | 2015 | 2016 and beyond | Total Fair Value | ||||||||||||||||||||||
Prices based on model or other valuation methods(a) | $ | (219 | ) | $ | (403 | ) | $ | (155 | ) | $ | (10 | ) | (7 | ) | $ | 6 | $ | (788 | ) |
(a) | Represents ComEd’s net |
PECO
Maturities Within | ||||||||||||||||||||||||
2010 | 2011 | 2012 | 2013 | 2014 | Total Fair Value | |||||||||||||||||||
Prices based on model or other valuation methods(a) | $ | — | $ | (9 | ) | $ | — | $ | — | $ | — | $ | (9 | ) |
Maturities Within | ||||||||||||||||||||||||||||
2011 | 2012 | 2013 | 2014 | 2015 | 2016 and Beyond | Total Fair Value | ||||||||||||||||||||||
Prices based on model or other valuation methods(a) | $ | (4 | ) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (4 | ) |
(a) | Represents PECO’s net liabilities associated with its block contracts executed under its DSP Program. Includes |
Credit Risk, Collateral, and Contingent Related Features (Exelon, Generation, ComEd and PECO)
The Registrants are exposed to credit-related losses in the event of non-performance by counterparties with whom they that enter into derivative instruments. The credit exposure of derivative contracts, before collateral and netting, is represented by the fair value of contracts at the reporting date. See Note 6 of the Combined Notes to Consolidated Financial Statements for a detail discussion of credit risk, collateral, and contingent related features.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2010.2011. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs and NYMEX and ICE commodity exchanges, which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $44$43 million and $194$43 million, respectively. See Note 21 of the 20092010 Form 10-K for further information.
Total | Number of | Net Exposure of | ||||||||||||||||||
Exposure | Counterparties | Counterparties | ||||||||||||||||||
Before Credit | Credit | Net | Greater than 10% | Greater than 10% | ||||||||||||||||
Rating as of June 30, 2010 | Collateral | Collateral | Exposure | of Net Exposure | of Net Exposure | |||||||||||||||
Investment grade | $ | 1,301 | $ | 452 | $ | 849 | — | $ | — | |||||||||||
Non-investment grade | 9 | 5 | 4 | — | — | |||||||||||||||
No external ratings | ||||||||||||||||||||
Internally rated — investment grade | 38 | 5 | 33 | — | — | |||||||||||||||
Internally rated — non-investment grade | 1 | 1 | — | — | — | |||||||||||||||
Total | $ | 1,349 | $ | 463 | $ | 886 | — | $ | — | |||||||||||
Rating as of June 30, 2011 | Total Exposure Before Credit Collateral | Credit Collateral | Net Exposure | Number of Counterparties Greater than 10% of Net Exposure | Net Exposure of Counterparties Greater than 10% of Net Exposure | |||||||||||||||
Investment grade | $ | 1,058 | $ | 280 | $ | 778 | 2 | $ | 190 | |||||||||||
Non-investment grade | 13 | 5 | 8 | — | — | |||||||||||||||
No external ratings | ||||||||||||||||||||
Internally rated — investment grade | 37 | 7 | 30 | — | — | |||||||||||||||
Internally rated — non-investment grade | 4 | 2 | 2 | — | — | |||||||||||||||
Total | $ | 1,112 | $ | 294 | $ | 818 | 2 | $ | 190 | |||||||||||
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Maturity of Credit Risk Exposure | ||||||||||||||||
Rating as of June 30, 2011 | Less than 2 Years | 2-5 Years | Exposure Greater than 5 Years | Total Exposure Before Credit Collateral | ||||||||||||
Investment grade | $ | 849 | $ | 161 | $ | 48 | $ | 1,058 | ||||||||
Non-investment grade | 13 | — | — | 13 | ||||||||||||
No external ratings | ||||||||||||||||
Internally rated — investment grade | 30 | 7 | — | 37 | ||||||||||||
Internally rated — non-investment grade | 4 | — | — | 4 | ||||||||||||
Total | $ | 896 | $ | 168 | $ | 48 | $ | 1,112 | ||||||||
Net Credit Exposure by Type of Counterparty | As of June 30, 2011 | |||
Financial institutions | $ | 320 | ||
Investor-owned utilities, marketers and power producers | 310 | |||
Energy cooperatives and municipalities | 163 | |||
Other | 25 | |||
Total | $ | 818 | ||
Maturity of Credit Risk Exposure | ||||||||||||||||
Exposure | Total Exposure | |||||||||||||||
Less than | Greater than | Before Credit | ||||||||||||||
Rating as of June 30, 2010 | 2 Years | 2-5 Years | 5 Years | Collateral | ||||||||||||
Investment grade | $ | 1,104 | $ | 197 | $ | — | $ | 1,301 | ||||||||
Non-investment grade | 9 | — | — | 9 | ||||||||||||
No external ratings | ||||||||||||||||
Internally rated — investment grade | 26 | 12 | — | 38 | ||||||||||||
Internally rated — non-investment grade | 1 | — | — | 1 | ||||||||||||
Total | $ | 1,140 | $ | 209 | $ | — | $ | 1,349 | ||||||||
Net Credit Exposure by Type of Counterparty | As of June 30, 2010 | |||
Financial institutions | $ | 307 | ||
Investor-owned utilities, marketers and power producers | 490 | |||
Coal | 4 | |||
Other | 85 | |||
Total | $ | 886 | ||
There have been no significant changes or additions to ComEd’s exposures to credit risk that are described in Item 1A. Risk Factors of Exelon’s 20092010 Annual Report on Form 10-K.
ComEd’s power procurement contracts provide suppliers with a certain amount of the Combined Notesunsecured credit. The credit position is based on forward market prices compared to the Consolidated Financial Statementsbenchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for information regardingthe secured credit portion. The unsecured credit used by the suppliers represents ComEd’s recently approved tariffscredit exposure. As of June 30, 2011, ComEd’s credit exposure to adjust rates annually through a rider mechanism to reflect increases or decreases in annual uncollectible accounts expense.
PECO
There have been no significant changes or additions to PECO’s exposures to credit risk including that PECO could be negatively affected if Generation could not perform under the PPA, that areas described in Item 1A. Risk Factors of Exelon’s 20092010 Annual Report on Form 10-K.
See Note 6 of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.
Collateral (Generation, ComEd and PECO)
Generation
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels, RECs and emissions allowances. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.
Generation sells output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. In order to post collateral, Exelon depends on access to bank credit lines which serve as liquidity sources to fund collateral requirements. Since the banking industry issues started to surface in mid-2007, credit markets have tightened. Exelon will be required to renew most of its credit facilities in the 2011-2012 timeframe. The cost and availability to renew may be substantially different than when Exelon originally negotiated the existing liquidity facilities.
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ComEd
As of June 30, 2010, there was an2011, ComEd held immaterial amountamounts of cash collateral and letters of credit posted by energyfor the purpose of collateral from suppliers to ComEd associatedin association with energy procurement contracts and held approximately $20 million in the form of cash and letters of credit for both annual and long-term renewable energy contracts.
PECO
As of June 30, 2010,2011, PECO was not required to post, nor does it hold collateral under its energy and natural gas procurement contracts. ReferSee to Note 6 — 6—Derivative Financial Instruments for further discussion.
RTOs and ISOs (Exelon, Generation, ComEd and PECO)
Generation, ComEd and PECO participate in all, or some, of the established, real-time energy markets that are administered by PJM, ISO-NE, New York ISO, California ISO, MISO, Southwest Power Pool, Inc. and the Electric Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are operated by the RTOs or ISOs, as applicable. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.
Exchange Traded Transactions (Exelon and Generation)
Generation enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearinghouse actsclearinghouses act as the counterparty to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX and ICE are significantly collateralized and have limited counterparty credit risk.
Direct FinancingLong-Term Leases (Exelon)
Exelon’s consolidated balance sheets, as of June 30, 2010,2011, included a $615$642 million net investment in direct financingcoal-fired plants in Georgia and Texas subject to long-term leases. TheThis investment in direct financing leases represents the estimated residual value of leased assets at the end of the respective lease terms of approximately $1.5 billion, less unearned income of $877$850 million. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms.terms which are set at prices above expected fair market value of the plants at lease inception. If the lessees do not exercise the fixed purchase options the lessees return the leasehold interests to Exelon and Exelon has the ability to require the lessees to return the leasehold interests or to arrange a service contract with a third party for a period following the lease term. If Exelon chooses the service contract option, the leasehold interests will be returned to Exelon at the end of the term of the service contract. In any event, Exelon will beis subject to residual value risk ifto the lessees do not exerciseextent the fair value of the assets are less than the residual value. This risk is mitigated by the fair value of the fixed purchase options.payments under the service contract. The term of the service contract, however, is less than the expected remaining useful life of the plants and, therefore Exelon’s exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. Lessee performance under the lease agreements is supported by collateral and credit enhancement measures, including letters of credit, surety bonds and credit swaps. Management regularly evaluates the credit worthiness of Exelon’s counterparties to these direct financinglong-term leases. DuringSince 2008, and 2009, the entity providing the credit enhancement for one of the lessees did not meet the credit rating requirements of the lease. Consequently, Exelon has indefinitely extended a waiver and reduction of the rating requirement, which Exelon may terminate by giving 90 days notice to the lessee.
Exelon monitors the continuing credit quality of the credit enhancement party.
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The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also use interest rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants may use forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financings. These strategies are employed to achieve a lower cost of capital.manage interest rate risks. At June 30, 2010,2011, Exelon had $100 million of notional amounts of fair value hedges outstanding. At June 30, 2010, ComEd had $300 million of notional amounts of cash flow hedges outstanding. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in Exelon’s, Generation’sComEd’s and ComEd’sPECO’s pre-tax earnings for the six months ended June 30, 2010.2011. This calculation holds all other variable constant and assumes only the discussed changes in interest rates.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of June 30, 2010,2011, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $369$410 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Item 2,2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further discussion of equity price risk as a result of the current capital and credit market conditions.
During the second quarter of 2010,2011, each of Exelon’s, Generation’s, ComEd’s and PECO’s management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each of Exelon, Generation, ComEd and PECO to ensure that (a) material information relating to Exelon,that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of Exelonthat Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of June 30, 2010,2011, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd and PECO concluded that Exelon’ssuch Registrant’s disclosure controls and procedures were effective to accomplish its objectives. Exelon, Generation, ComEd and PECO continually strivesstrive to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of 2010 that have materially affected, or are reasonably likely to materially affect, Exelon’s internal control over financial reporting.
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The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. Legal Proceedings of the Registrants’ 2009 Annual Report on2010 Form 10-K and (b) Notes 3, 4 and 1213 of the Combined Notes to Consolidated Financial Statements in Part I, Item 1 of this Report. Such descriptions are incorporated herein by these references.
Item 1A. | Risk Factors |
Risks Related to Exelon
Exelon is, and will continue to be, subject to the risks described in Exelon’s 2010 Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18 — Commitments and Contingencies. As a result of the merger agreement announced with Constellation on April 28, 2011, Exelon is subject to additional risks related to the merger as described below.
Risks Related to the Merger
Because the market price of shares of Exelon common stock will fluctuate and the exchange ratio will not be adjusted to reflect such fluctuations, the merger consideration at the date of the closing may vary significantly from the date the merger agreement was executed.
Upon completion of the merger, each outstanding share of Constellation common stock will be converted into the right to receive 0.930 of a share of Exelon common stock. The number of shares of Exelon common stock to be issued pursuant to the merger agreement for each share of Constellation common stock will not change to reflect changes in the market price of Exelon or Constellation common stock. The market price of Exelon common stock at the time of completion of the merger may vary significantly from the market prices of Exelon common stock on the date the merger agreement was executed.
In addition, Exelon might not complete the merger until a significant period of time has passed after the respective special shareholder meetings. Because Exelon will not adjust the exchange ratio to reflect any changes in the market value of Exelon common stock or Constellation common stock, the market value of the Exelon common stock issued in connection with the merger and the Constellation common stock surrendered in connection with the merger may be higher or lower than the values of those shares on earlier dates. Stock price changes may result from market reaction to the announcement of the merger and market assessment of the likelihood that the merger will be completed, changes in the business, operations or prospects of Exelon or Constellation prior to or following the merger, litigation or regulatory considerations, general business, market, industry or economic conditions and other factors both within and beyond the control of Exelon and Constellation. Neither Exelon nor Constellation is permitted to terminate the merger agreement solely because of changes in the market price of either company’s common stock.
The merger agreement contains provisions that limit each of Exelon’s and Constellation’s ability to pursue alternatives to the merger, which could discourage a potential acquirer of either Constellation or Exelon from making an alternative transaction proposal and, in certain circumstances, could require Exelon or Constellation to pay to the other a significant termination fee.
Under the merger agreement, Exelon and Constellation are restricted, subject to limited exceptions, from entering into alternative transactions in lieu of the merger. In general, unless and until the merger agreement is terminated, both Exelon and Constellation are restricted from, among other things, soliciting, initiating,
knowingly encouraging or facilitating a competing acquisition proposal from any person. Each of the Exelon board of directors and the Constellation board of directors is limited in its ability to change its recommendation with respect to the merger-related proposals. Exelon or Constellation may terminate the merger agreement and enter into an agreement with respect to a superior proposal only if specified conditions have been satisfied, including compliance with the non-solicitation provisions of the merger agreement. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of Exelon or Constellation from considering or proposing such an acquisition, even if such third party were prepared to pay consideration with a higher per share cash or market value than the consideration proposed to be received or realized in the merger, or might result in a potential competing acquirer proposing to pay a lower price than it would otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances. Under the merger agreement, in the event Exelon or Constellation terminates the merger agreement to accept a superior proposal, or under certain other circumstances, Exelon or Constellation, as applicable, would be required to pay a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon.
Exelon and Constellation will be subject to various uncertainties and contractual restrictions while the merger is pending that may cause disruption and could adversely affect their financial results.
Uncertainty about the effect of the merger on employees, suppliers and customers may have an adverse effect on Exelon and/or Constellation. These uncertainties may impair Exelon’s and/or Constellation’s ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, as employees and prospective employees may experience uncertainty about their future roles with the combined company, and could cause customers, suppliers and others who deal with Exelon or Constellation to seek to change existing business relationships with Exelon or Constellation. The pursuit of the merger and the preparation for the integration may also place a burden on management and internal resources. Any significant diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect Exelon’s and/or Constellation’s financial results.
In addition, the merger agreement restricts each of Exelon and Constellation, without the other’s consent, from making certain acquisitions and taking other specified actions while the merger is pending. These restrictions may prevent Exelon and/or Constellation from pursuing otherwise attractive business opportunities and making other changes to their respective businesses prior to completion of the merger or termination of the merger agreement.
If completed, the merger may not achieve its anticipated results, and Exelon and Constellation may be unable to integrate their operations in the manner expected.
Exelon and Constellation entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Exelon and Constellation can be integrated in an efficient, effective and timely manner.
It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of each company’s ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. The combined company’s results of operations could also be adversely affected by any issues attributable to either company’s operations that arise or are based on events or actions that occur prior to the closing of the merger. The companies may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company’s future business, financial condition, operating results and prospects.
The merger may not be accretive to earnings and may cause dilution to Exelon’s earnings per share, which may negatively affect the market price of Exelon’s common stock.
Exelon currently anticipates that the merger will be accretive to earnings per share in 2013, which is expected to be the first full year following completion of the merger. This expectation is based on preliminary estimates that are subject to change. Exelon also could encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Exelon’s common stock.
Exelon may record goodwill that could become impaired and adversely affect its operating results.
Accounting standards in the United States require that one party to the merger be identified as the acquirer. In accordance with these standards, the merger will be accounted for as an acquisition of Constellation common stock by Exelon and will follow the acquisition method of accounting for business combinations. The assets and liabilities of Constellation will be consolidated with those of Exelon. The excess of the purchase price over the fair values of Constellation’s assets and liabilities, if any, will be recorded as goodwill.
The amount of goodwill, which could be material, will be allocated to the appropriate reporting units of the combined company. Exelon is required to assess goodwill for impairment at least annually by comparing the fair value of reporting units to the carrying value of those reporting units. To the extent the carrying value of any of those reporting units is greater than the fair value, a second step comparing the implied fair value of goodwill to the carrying amount would be required to determine if the goodwill is impaired. Such a potential impairment could result in a material charge that would have a material impact on Exelon’s future operating results and consolidated balance sheet.
Pending litigation against Exelon and Constellation could result in an injunction preventing the completion of the merger or a judgment resulting in the payment of damages in the event the merger is completed and may adversely affect the combined company’s business, financial condition or results of operations and cash flows following the merger.
Exelon and Constellation are aware of 12 purported class action lawsuits that plaintiffs have filed against Constellation, each member of Constellation’s board of directors, Exelon and Bolt Acquisition Corporation, a Maryland corporation and a wholly-owned subsidiary of Exelon, in connection with the merger. Among other things, the lawsuits seek injunctive relief that would prevent completion of the merger in accordance with the terms of the merger agreement. The outcome of any such litigation is uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay completion of the merger and result in substantial costs to Exelon and Constellation, including any costs associated with the indemnification of directors and officers. Plaintiffs may file additional lawsuits against Exelon, Constellation and/or the directors and officers of either company in connection with the merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect the combined company’s business, financial condition, results of operations and cash flows.
The merger is subject to the receipt of consent or approval from governmental entities that could delay the completion of the merger or impose conditions that could have a material adverse effect on the combined company or that could cause abandonment of the merger.
Completion of the merger is conditioned upon the receipt of consents, orders, approvals or clearances, to the extent required, from the FERC, the NRC, the FCC, and the public utility commissions or similar entities in certain states in which the companies operate, including the Maryland Public Service Commission. The merger is also subject to review by the DOJ Antitrust Division, under the HSR Act, and the expiration or earlier
termination of the waiting period (and any extension of the waiting period) applicable to the merger is a condition to closing the merger. The special meetings of the shareholders of Exelon and Constellation at which the proposals required to complete the merger will be considered may take place before any or all of the required regulatory approvals have been obtained and before all conditions to such approvals, if any, are known.
In this event, if the shareholder proposals required to complete the merger are approved, Exelon and Constellation may subsequently agree to conditions without seeking further shareholder approval, even if such conditions could have an adverse effect on Exelon, Constellation or the combined company.
Exelon and Constellation cannot provide assurance that we will obtain all required regulatory consents or approvals or that these consents or approvals will not contain terms, conditions or restrictions that would be detrimental to the combined company after the completion of the merger. The merger agreement generally permits each party to terminate the merger agreement if the final terms of any of the required regulatory consents or approvals require (1) any action that involves divesting, holding separate or otherwise transferring control over any nuclear or hydroelectric or pumped-storage generation assets of the parties or any of their respective subsidiaries or affiliates; or (2) any action (including any action that involves divesting, holding separate or otherwise transferring control over base-load capacity), without including those actions proposed by the parties’ mutually agreed-upon analysis of mitigation to address the increased market concentration resulting from the merger and the concessions announced by the parties in the press release announcing the merger agreement, which would, individually or in the aggregate, reasonably be expected to have a material adverse effect on either party. Any substantial delay in obtaining satisfactory approvals, receipt of proceeds from required divestitures in an amount substantially lower than anticipated or the imposition of any terms or conditions in connection with such approvals could cause a material reduction in the expected benefits of the merger. If any such delays or conditions are serious enough, the parties may decide to abandon the merger.
Exelon cannot assure that it will be able to continue paying dividends at the current rate.
Exelon currently expects to pay dividends in an amount consistent with the dividend policy of Exelon in effect prior to the completion of the merger. However, there is no assurance that Exelon shareholders will receive the same dividends following the merger for reasons that may include any of the following factors:
Exelon may not have enough cash to pay such dividends due to changes in Exelon’s cash requirements, capital spending plans, financing agreements, cash flow or financial position;
decisions on whether, when and in which amounts to make any future distributions will remain at all times entirely at the discretion of the Exelon board of directors, which reserves the right to change Exelon’s dividend practices at any time and for any reason;
the amount of dividends that Exelon may distribute to its shareholders is subject to restrictions under Pennsylvania law; and
Exelon may not receive dividend payments from its subsidiaries in the same level that it has historically. The ability of Exelon’s subsidiaries to make dividend payments to it is subject to factors similar to those listed above.
Exelon’s shareholders should be aware that they have no contractual or other legal right to dividends that have not been declared.
If completed, the merger may adversely affect the combined company’s ability to attract and retain key employees.
Current and prospective Exelon and Constellation employees may experience uncertainty about their future roles at the combined company following the completion of the proposed merger. In addition, current and prospective Exelon and Constellation employees may determine that they do not desire to work for the combined company for a variety of possible reasons. These factors may adversely affect the combined company’s ability to attract and retain key management and other personnel.
Failure to complete the merger could negatively affect the share prices and the future businesses and financial results of Exelon and Constellation.
Completion of the merger is not assured and is subject to risks, including the risks that approval of the transaction by shareholders of Exelon and Constellation or by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If the merger is not completed, the ongoing businesses of Exelon or Constellation may be adversely affected and Exelon and Constellation will be subject to several risks, including:
having to pay certain significant costs relating to the merger without receiving the benefits of the merger, including, in certain circumstances, a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon;
the potential loss of key personnel during the pendency of the merger as employees may experience uncertainty about their future roles with the combined company;
Exelon and Constellation will have been subject to certain restrictions on the conduct of their businesses, which may have prevented them from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending; and
the share price of Exelon or Constellation may decline to the extent that the current market prices reflect an assumption by the market that the merger will be completed.
Exelon and Constellation may incur unexpected transaction fees and merger-related costs in connection with the merger.
Exelon and Constellation expect to incur a number of non-recurring expenses, totalling approximately $144 million, associated with completing the merger, as well as expenses related to combining the operations of the two companies. The combined company may incur additional unanticipated costs in the integration of the businesses of Exelon and Constellation. Although Exelon expects that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.
Current Exelon shareholders and Constellation stockholders will have a reduced ownership and voting interest after the merger.
Exelon will issue or reserve for issuance approximately 201.9 million shares of Exelon common stock to Constellation stockholders in the merger (including shares of Exelon common stock issuable pursuant to Constellation stock options and other equity-based awards). Based on the number of shares of common stock of Exelon and Constellation outstanding on March 31, 2011, the record date for the two companies’ special meetings of shareholders, upon the completion of the merger, current Exelon shareholders and former Constellation stockholders would own approximately 78% and 22% of the outstanding shares of Exelon common stock, respectively, immediately following the consummation of the merger.
Exelon shareholders and Constellation stockholders currently have the right to vote for their respective directors and on other matters affecting their company. When the merger occurs, each Constellation stockholder who receives shares of Exelon common stock will become a shareholder of Exelon with a percentage ownership of the combined company that will be smaller than the shareholder’s percentage ownership of Constellation.
Correspondingly, each Exelon shareholder will remain a shareholder of Exelon with a percentage ownership of the combined company that will be smaller than the shareholder’s percentage of Exelon prior to the merger. As a result of these reduced ownership percentages, Exelon shareholders will have less voting power in the combined company than they now have with respect to Exelon, and former Constellation stockholders will have less voting power in the combined company than they now have with respect to Constellation.
Item 6. | Exhibits |
Exhibit No. | Description |
2-1 | Purchase Agreement dated as of April 28, 2011 by and between Exelon Corporation, Bolt Acquisition Corporation and Constellation Energy Group, Inc. (File No. 333-85496, Form 8-K dated April 28, 2011, Exhibit No. 2-1) | |
101.INS* | XBRL Instance | ||
101.SCH* | XBRL Taxonomy Extension Schema | ||
101.CAL* | XBRL Taxonomy Extension Calculation | ||
101.DEF* | XBRL Taxonomy Extension Definition | ||
101.LAB* | XBRL Taxonomy Extension Labels | ||
101.PRE* | XBRL Taxonomy Extension Presentation |
* | XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information. |
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 20102011 filed by the following officers for the following companies:
31-1 | — Filed by John W. Rowe for Exelon Corporation | |
31-2 | — Filed by Matthew F. Hilzinger for Exelon Corporation | |
31-3 | — Filed by John W. Rowe for Exelon Generation Company, LLC | |
31-4 | — Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC | |
31-5 | — Filed by Frank M. Clark for Commonwealth Edison Company | |
31-6 | — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company | |
31-7 | — Filed by Denis P. O’Brien for PECO Energy Company | |
31-8 | — Filed by Phillip S. Barnett for PECO Energy Company |
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32-1 | — Filed by John W. Rowe for Exelon Corporation | |
32-2 | — Filed by Matthew F. Hilzinger for Exelon Corporation | |
32-3 | — Filed by John W. Rowe for Exelon Generation Company, LLC | |
32-4 | — Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC | |
32-5 | — Filed by Frank M. Clark for Commonwealth Edison Company | |
32-6 | — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company | |
32-7 | — Filed by Denis P. O’Brien for PECO Energy Company | |
32-8 | — Filed by Phillip S. Barnett for PECO Energy Company |
/s/ JOHN W. ROWE | ||
/s/ | ||
HILZINGER | ||
John W. Rowe | Matthew F. Hilzinger | |
Chairman and Chief Executive Officer (Principal Executive Officer) | Senior Vice President, | |
and Treasurer (Principal Financial Officer) | ||
/s/ DUANE M. DESPARTE | ||
Duane M. DesParte | ||
Vice President and Corporate Controller | ||
(Principal Accounting Officer) |
July 22, 2010
Pursuant to 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.
/s/ JOHN W. ROWE | ||
/s/ | ||
HILZINGER | ||
John W. Rowe | Matthew F. Hilzinger | |
Chairman (Principal Executive Officer) | Chief Financial Officer and Treasurer (Principal Financial Officer) | |
/s/ MATTHEW R. GALVANONI | ||
Matthew R. Galvanoni | ||
Chief Accounting Officer | ||
(Principal Accounting Officer) |
July 22, 2010
27, 2011
147
/s/ FRANK M. CLARK | ||
/s/ | ||
PRAMAGGIORE | ||
Frank M. Clark | Anne R. Pramaggiore | |
Chairman and Chief Executive Officer (Principal Executive Officer) | President and Chief Operating Officer | |
/s/ JOSEPH R. TRPIK, JR. | ||
/s/ | ||
WADEN | ||
Joseph R. Trpik, Jr. | Kevin J. Waden | |
Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | Vice President and Controller | |
(Principal Accounting Officer) |
July 22, 2010
Pursuant to 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.
/s/ DENIS P. O’BRIEN | ||
/s/ | ||
BARNETT | ||
Denis P. O’Brien | Phillip S. Barnett | |
Chief Executive Officer and President (Principal Executive Officer) | Senior Vice President and | |
Chief Financial Officer | ||
(Principal Financial Officer) | ||
/s/ JORGE A. ACEVEDO | ||
Jorge A. Acevedo | ||
Vice President and Controller | ||
(Principal Accounting Officer) |
July 22, 2010
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