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 September 30, 2011March 31, 2012
or
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission
| 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 | ||||||
1-1910 | BALTIMORE GAS AND ELECTRIC COMPANY | 52-0280210 | ||||
(a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, MD 21201-3708 (410) 234-5000 |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
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 | |||||||||||
Baltimore Gas and Electric Company | þ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ.
The number of shares outstanding of each registrant’s common stock as of September 30, 2011March 31, 2012 was:
Exelon Corporation Common Stock, without par value | ||
Exelon Generation Company, LLC | not applicable | |
Commonwealth Edison Company Common Stock, $12.50 par value | ||
PECO Energy Company Common Stock, without par value | 170,478,507 | |
Baltimore Gas and Electric Company Common Stock, without par value | 1,000 |
Page No. | ||||||
FILING FORMAT | 6 | |||||
FORWARD-LOOKING STATEMENTS | 6 | |||||
WHERE TO FIND MORE INFORMATION | 6 | |||||
PART I. | 7 | |||||
ITEM 1. | 7 | |||||
8 | ||||||
Consolidated Statements of Operations and Comprehensive Income | 8 | |||||
9 | ||||||
10 | ||||||
12 | ||||||
13 | ||||||
Consolidated Statements of Operations and Comprehensive Income | 13 | |||||
14 | ||||||
15 | ||||||
17 | ||||||
18 | ||||||
Consolidated Statements of Operations and Comprehensive Income | 18 | |||||
19 | ||||||
20 | ||||||
22 | ||||||
23 | ||||||
Consolidated Statements of Operations and Comprehensive Income | 23 | |||||
24 | ||||||
25 | ||||||
27 | ||||||
28 | ||||||
Consolidated Statements of Operations and Comprehensive Income | 28 | |||||
29 | ||||||
30 | ||||||
32 | ||||||
6. | ||||||
Page No. | ||||||
88 | ||||||
91 | ||||||
94 | ||||||
99 | ||||||
100 | ||||||
14. | ||||||
104 | ||||||
119 | ||||||
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | |||||
| ||||||
ITEM 3. | ||||||
ITEM 4. | ||||||
PART II. | ||||||
ITEM 1. | ||||||
ITEM 1A. | ||||||
ITEM 4. | 188 | |||||
ITEM 6. | ||||||
SIGNATURES | ||||||
193 | ||||||
CERTIFICATION EXHIBITS | ||||||
Exelon Corporation | ||||||
Exelon Generation Company, LLC | ||||||
Commonwealth Edison Company | ||||||
PECO Energy Company | ||||||
Baltimore Gas and Electric Company | 202, 212 |
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 | |||
BGE | Baltimore Gas and Electric Company | |||
BSC | Exelon Business Services Company, LLC | |||
Exelon Corporate | Exelon’s holding company | |||
CENG | Constellation Energy Nuclear Group, LLC | |||
Constellation | Constellation Energy Group, Inc. | |||
Exelon Transmission Company | Exelon Transmission Company, LLC | |||
Exelon Wind | Exelon Wind, LLC and Exelon Generation | |||
Enterprises | Exelon Enterprises Company, LLC | |||
Ventures | Exelon Ventures Company, LLC | |||
AmerGen | AmerGen Energy Company, LLC | |||
| ||||
PECO Trust III | PECO Capital Trust III | |||
PECO Trust IV | PECO Energy Capital Trust IV | |||
| ||||
Registrants | Exelon, Generation, ComEd, PECO and | |||
Other Terms and Abbreviations | ||||
Note “ ” of the | Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s | |||
| ||||
Act | Pennsylvania Act | |||
AEC | Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source | |||
| ||||
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 of 2009 | American Recovery and Reinvestment Act of 2009 | |||
| ||||
Block contracts | Forward Purchase Energy Block Contracts | |||
CAIR | Clean Air Interstate Rule | |||
CAMR | Federal Clean Air Mercury Rule | |||
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended | |||
| ||||
Clean Water Act | Federal Water Pollution Control Amendments of 1972, as amended | |||
Competition Act | Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996 | |||
| ||||
CTC | Competitive Transition Charge | |||
DOE | United States Department of Energy | |||
DOJ | United States Department of Justice | |||
DSP | Default Service Provider | |||
EDF | Electricite de France SA | |||
EE&C | Energy Efficiency and Conservation/Demand Response | |||
EGS | Electric Generation Supplier | |||
EIMA | Illinois Senate Bill 1652 and Illinois House Bill 3036 | |||
EPA | United States Environmental Protection Agency | |||
| ||||
| ||||
|
GLOSSARY OF TERMS AND ABBREVIATIONS | ||||
Exelon Corporation and Related Entities | ||||
Other Terms and Abbreviations | ||||
ERCOT | Electric Reliability Council of Texas | |||
| Employee | |||
EROA | Expected Rate of Return on Assets | |||
FASB | Financial Accounting Standards Board | |||
FERC | Federal Energy Regulatory Commission | |||
| ||||
GAAP | Generally Accepted Accounting Principles in the United States | |||
GHG | Greenhouse Gas | |||
GRT | Gross Receipts Tax | |||
GSA | Generation Supply Adjustment | |||
GWh | Gigawatt hour | |||
HAP | Hazardous air pollutants | |||
Health Care Reform Acts | Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010 | |||
| ||||
ICC | Illinois Commerce Commission | |||
ICE | Intercontinental Exchange | |||
| ||||
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 | |||
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 | |||
MATS | U.S. EPA Mercury and Air Toxics Rule | |||
MDPSC | Maryland Public Service Commission | |||
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 | |||
n.m. | not meaningful | |||
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 | |||
| ||||
NOV | Notice of Violation |
GLOSSARY OF TERMS AND ABBREVIATIONS | ||
Exelon Corporation and Related Entities | ||
Other Terms and Abbreviations | ||
NPDES | National Pollutant Discharge Elimination System | |
NRC | Nuclear Regulatory Commission | |
|
| ||
| ||
NYMEX | New York Mercantile Exchange | |
OCI | Other Comprehensive Income | |
OIESO | Ontario Independent Electricity System Operator | |
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 | |
| ||
PRP | Potentially Responsible Parties | |
PSEG | Public Service Enterprise Group Incorporated | |
| ||
| ||
RCRA | ||
REC | Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source | |
Regulatory Agreement Units | ||
RES | Retail Electric Suppliers | |
RFP | Request for Proposal | |
| ||
Rider | Reconcilable Surcharge Recovery Mechanism | |
RMC | Risk Management Committee | |
RPM | PJM Reliability Pricing Model | |
RPS | Renewable Energy Portfolio Standards | |
| ||
RTEP | Regional Transmission Expansion Plan | |
RTO | Regional Transmission Organization | |
S&P | Standard & Poor’s Ratings Services | |
SEC | United States Securities and Exchange Commission | |
| ||
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 | |
SOS | Standard Offer Service | |
SPP | Southwest Power Pool | |
SSCM | Simplified Service Cost Method | |
Tax Relief Act of 2010 | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 | |
TEG | Termoelectrica del Golfo | |
TEP | Termoelectrica Penoles | |
Upstream | Natural gas exploration and production activities | |
VIE | Variable Interest Entity | |
WECC | Western Electric Coordinating Council |
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 Registrant include (a) those factors discussed in the following sections of the Registrants’ 2010Exelon’s 2011 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 1315 of this Report; (b) those factors discussed in the following sections of the Constellation Energy Group, Inc.’s 2011 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 (b)ITEM 8. Financial Statements and Supplementary Data: Note 12, as updated by Part I, ITEM 1. Financial Statements, Note 15 of this Report; and (c) 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.
WHERE TO FIND MORE INFORMATION
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.
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
(In millions, except per share data) | 2011 | 2010 | 2011 | 2010 | 2012 | 2011 | ||||||||||||||||||
Operating revenues | $ | 5,295 | $ | 5,291 | $ | 14,933 | $ | 14,150 | $ | 4,686 | $ | 4,956 | ||||||||||||
Operating expenses | ||||||||||||||||||||||||
Purchased power | 1,711 | 1,481 | 4,602 | 3,273 | ||||||||||||||||||||
Fuel | 451 | 475 | 1,462 | 1,469 | ||||||||||||||||||||
Purchased power and fuel | 1,765 | 2,001 | ||||||||||||||||||||||
Operating and maintenance | 1,354 | 1,122 | 3,725 | 3,298 | 1,964 | 1,223 | ||||||||||||||||||
Operating and maintenance for regulatory required programs | 59 | 37 | 138 | 98 | ||||||||||||||||||||
Depreciation and amortization | 332 | 578 | 987 | 1,611 | 382 | 327 | ||||||||||||||||||
Taxes other than income | 207 | 232 | 602 | 615 | 194 | 203 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating expenses | 4,114 | 3,925 | 11,516 | 10,364 | 4,305 | 3,754 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Equity in loss of unconsolidated affiliates | (22 | ) | — | |||||||||||||||||||||
Operating income | 1,181 | 1,366 | 3,417 | 3,786 | 359 | 1,202 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other income and deductions | ||||||||||||||||||||||||
Interest expense | (176 | ) | (169 | ) | (526 | ) | (615 | ) | (189 | ) | (175 | ) | ||||||||||||
Interest expense to affiliates, net | (6 | ) | (6 | ) | (19 | ) | (19 | ) | (6 | ) | (6 | ) | ||||||||||||
Other, net | (143 | ) | 206 | 51 | 178 | 194 | 94 | |||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total other income and deductions | (325 | ) | 31 | (494 | ) | (456 | ) | (1 | ) | (87 | ) | |||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Income before income taxes | 856 | 1,397 | 2,923 | 3,330 | 358 | 1,115 | ||||||||||||||||||
Income taxes | 255 | 552 | 1,034 | 1,291 | 158 | 446 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net income | 601 | 845 | 1,889 | 2,039 | 200 | 669 | ||||||||||||||||||
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends | — | 1 | ||||||||||||||||||||||
|
| |||||||||||||||||||||||
Net income on common stock | 200 | 668 | ||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||||||||||
Prior service benefit reclassified to periodic (cost) benefit | (1 | ) | 3 | (3 | ) | (8 | ) | |||||||||||||||||
Prior service cost (benefit) reclassified to periodic benefit cost | 1 | (1 | ) | |||||||||||||||||||||
Actuarial loss reclassified to periodic cost | 33 | 24 | 100 | 86 | 41 | 33 | ||||||||||||||||||
Transition obligation reclassified to periodic cost | 1 | — | 2 | 5 | 1 | 1 | ||||||||||||||||||
Pension and non-pension postretirement benefit plans valuation adjustment | — | 2 | 39 | (18 | ) | (8 | ) | 39 | ||||||||||||||||
Change in unrealized gain (loss) on cash flow hedges | (64 | ) | 222 | (255 | ) | 196 | 215 | (46 | ) | |||||||||||||||
Change in unrealized gain on marketable securities | 1 | — | ||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other comprehensive income (loss) | (31 | ) | 251 | (117 | ) | 261 | ||||||||||||||||||
Other comprehensive income | 251 | 26 | ||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income | $ | 570 | $ | 1,096 | $ | 1,772 | $ | 2,300 | $ | 451 | $ | 694 | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Average shares of common stock outstanding: | ||||||||||||||||||||||||
Weighted average shares of common stock outstanding: | ||||||||||||||||||||||||
Basic | 663 | 662 | 663 | 661 | 705 | 662 | ||||||||||||||||||
|
| |||||||||||||||||||||||
Diluted | 665 | 663 | 664 | 662 | 707 | 664 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Earnings per average common share: | ||||||||||||||||||||||||
Basic | $ | 0.91 | $ | 1.28 | $ | 2.85 | $ | 3.08 | ||||||||||||||||
Diluted | $ | 0.90 | $ | 1.27 | $ | 2.84 | $ | 3.08 | ||||||||||||||||
Earnings per average common share — basic: | $ | 0.28 | $ | 1.01 | ||||||||||||||||||||
|
| |||||||||||||||||||||||
Earnings per average common share — diluted: | $ | 0.28 | $ | 1.01 | ||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Dividends per common share | $ | 0.53 | $ | 0.53 | $ | 1.58 | $ | 1.58 | $ | 0.53 | $ | 0.53 | ||||||||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
(In millions) | 2011 | 2010 | 2012 | 2011 | ||||||||||||
Cash flows from operating activities | ||||||||||||||||
Net income | $ | 1,889 | $ | 2,039 | $ | 200 | $ | 669 | ||||||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||||||||||
Depreciation, amortization and accretion, including nuclear fuel amortization | 1,702 | 2,255 | ||||||||||||||
Adjustments to reconcile net income to net cash flows provided by (used in) operating activities: | ||||||||||||||||
Depreciation, amortization, accretion and depletion including nuclear fuel and energy contract amortization | 776 | 552 | ||||||||||||||
Deferred income taxes and amortization of investment tax credits | 1,008 | 240 | 101 | 340 | ||||||||||||
Net fair value changes related to derivatives | 360 | (281 | ) | (73 | ) | 148 | ||||||||||
Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments | 90 | (49 | ) | |||||||||||||
Net realized and unrealized gains on nuclear decommissioning trust fund investments | (103 | ) | (40 | ) | ||||||||||||
Other non-cash operating activities | 703 | 468 | 530 | 223 | ||||||||||||
Changes in assets and liabilities: | ||||||||||||||||
Accounts receivable | 3 | (172 | ) | 394 | 53 | |||||||||||
Inventories | (44 | ) | (52 | ) | 104 | 78 | ||||||||||
Accounts payable, accrued expenses and other current liabilities | (400 | ) | (53 | ) | (1,176 | ) | (526 | ) | ||||||||
Option premiums received (paid), net | 59 | (101 | ) | |||||||||||||
Option premiums (paid) received, net | (100 | ) | 19 | |||||||||||||
Counterparty collateral received (posted), net | (807 | ) | 289 | 340 | (150 | ) | ||||||||||
Income taxes | 532 | 310 | 178 | 733 | ||||||||||||
Pension and non-pension postretirement benefit contributions | (2,089 | ) | (740 | ) | (55 | ) | (2,088 | ) | ||||||||
Other assets and liabilities | (89 | ) | (41 | ) | (122 | ) | (218 | ) | ||||||||
|
|
|
| |||||||||||||
Net cash flows provided by operating activities | 2,917 | 4,112 | ||||||||||||||
Net cash flows provided by (used in) operating activities | 994 | (207 | ) | |||||||||||||
|
|
|
| |||||||||||||
Cash flows from investing activities | ||||||||||||||||
Capital expenditures | (2,972 | ) | (2,382 | ) | (1,496 | ) | (1,150 | ) | ||||||||
Proceeds from nuclear decommissioning trust fund sales | 3,120 | 2,756 | 3,680 | 1,195 | ||||||||||||
Investment in nuclear decommissioning trust funds | (3,293 | ) | (2,864 | ) | (3,726 | ) | (1,247 | ) | ||||||||
Acquisitions | (380 | ) | — | |||||||||||||
Cash acquired from Constellation | 964 | — | ||||||||||||||
Proceeds from sales of investments | 10 | 1 | ||||||||||||||
Purchases of investments | (5 | ) | (1 | ) | ||||||||||||
Change in restricted cash | (532 | ) | 427 | (8 | ) | 8 | ||||||||||
Other investing activities | 26 | 26 | (59 | ) | 15 | |||||||||||
|
|
|
| |||||||||||||
Net cash flows used in investing activities | (4,031 | ) | (2,037 | ) | (640 | ) | (1,179 | ) | ||||||||
|
|
|
| |||||||||||||
Cash flows from financing activities | ||||||||||||||||
Changes in short-term debt | 462 | (90 | ) | 141 | 50 | |||||||||||
Issuance of long-term debt | 1,199 | 1,398 | — | 599 | ||||||||||||
Retirement of long-term debt | (3 | ) | (827 | ) | (451 | ) | (1 | ) | ||||||||
Retirement of long-term debt of variable interest entity | — | (806 | ) | |||||||||||||
Dividends paid on common stock | (1,044 | ) | (1,042 | ) | (350 | ) | (348 | ) | ||||||||
Proceeds from employee stock plans | 26 | 34 | 12 | 8 | ||||||||||||
Other financing activities | (67 | ) | (17 | ) | (1 | ) | (47 | ) | ||||||||
|
|
|
| |||||||||||||
Net cash flows provided by (used in) financing activities | 573 | (1,350 | ) | |||||||||||||
Net cash flows (used in) provided by financing activities | (649 | ) | 261 | |||||||||||||
|
|
|
| |||||||||||||
Decrease (increase) in cash and cash equivalents | (541 | ) | 725 | |||||||||||||
Decrease in cash and cash equivalents | (295 | ) | (1,125 | ) | ||||||||||||
Cash and cash equivalents at beginning of period | 1,612 | 2,010 | 1,016 | 1,612 | ||||||||||||
|
|
|
| |||||||||||||
Cash and cash equivalents at end of period | $ | 1,071 | $ | 2,735 | $ | 721 | $ | 487 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
(Unaudited)
(In millions) | September 30, 2011 | December 31, 2010 | March 31, 2012 | December 31, 2011 | ||||||||||||
(Unaudited) | ||||||||||||||||
ASSETS | ||||||||||||||||
Current assets | ||||||||||||||||
Cash and cash equivalents | $ | 1,071 | $ | 1,612 | $ | 721 | $ | 1,016 | ||||||||
Restricted cash and investments | 565 | 30 | 43 | 40 | ||||||||||||
Restricted cash and investments of variable interest entities | 67 | — | ||||||||||||||
Accounts receivable, net | ||||||||||||||||
Customer ($351 and $346 gross accounts receivable pledged as collateral as of September 30, 2011 and December 31, 2010, respectively) | 1,685 | 1,932 | ||||||||||||||
Customer ($348 and $329 gross accounts receivable pledged as collateral as of March 31, 2012 and December 31, 2011, respectively) | 2,868 | 1,613 | ||||||||||||||
Other | 930 | 1,196 | 1,339 | 1,000 | ||||||||||||
Accounts receivable, net, variable interest entities | 241 | — | ||||||||||||||
Mark-to-market derivative assets | 478 | 487 | 1,491 | 432 | ||||||||||||
Unamortized energy contracts assets | 1,699 | 13 | ||||||||||||||
Inventories, net | ||||||||||||||||
Fossil fuel | 203 | 216 | 202 | 208 | ||||||||||||
Materials and supplies | 648 | 590 | 740 | 656 | ||||||||||||
Deferred income taxes | 183 | — | ||||||||||||||
Regulatory assets | 31 | 10 | 846 | 390 | ||||||||||||
Other | 493 | 325 | 1,558 | 345 | ||||||||||||
|
|
|
| |||||||||||||
Total current assets | 6,287 | 6,398 | 11,815 | 5,713 | ||||||||||||
|
|
|
| |||||||||||||
Property, plant and equipment, net | 31,882 | 29,941 | 42,105 | 32,570 | ||||||||||||
Deferred debits and other assets | ||||||||||||||||
Regulatory assets | 4,381 | 4,140 | 6,168 | 4,518 | ||||||||||||
Nuclear decommissioning trust funds | 6,226 | 6,408 | 6,927 | 6,507 | ||||||||||||
Investments | 740 | 717 | 827 | 751 | ||||||||||||
Investments in affiliates | 14 | 15 | 362 | 15 | ||||||||||||
Investment in CENG | 2,046 | — | ||||||||||||||
Goodwill | 2,625 | 2,625 | 2,625 | 2,625 | ||||||||||||
Mark-to-market derivative assets | 300 | 409 | 1,389 | 650 | ||||||||||||
Unamortized energy contracts assets | 1,530 | 388 | ||||||||||||||
Pledged assets for Zion Station decommissioning | 763 | 824 | 708 | 734 | ||||||||||||
Other | 938 | 763 | 1,126 | 524 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred debits and other assets | 15,987 | 15,901 | 23,708 | 16,712 | ||||||||||||
|
|
|
| |||||||||||||
Total assets | $ | 54,156 | $ | 52,240 | $ | 77,628 | $ | 54,995 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2011 | December 31, 2010 | March 31, 2012 | December 31, 2011 | ||||||||||||
(Unaudited) | ||||||||||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term borrowings | $ | 462 | $ | — | $ | 339 | $ | 163 | ||||||||
Short-term notes payable — accounts receivable agreement | 225 | 225 | 225 | 225 | ||||||||||||
Long-term debt due within one year | 1,239 | 599 | 670 | 828 | ||||||||||||
Long-term debt of variable interest entities due within one year | 65 | — | ||||||||||||||
Accounts payable | 1,388 | 1,373 | 2,125 | 1,444 | ||||||||||||
Accounts payable of variable interest entities | 138 | — | ||||||||||||||
Accrued expenses | 1,053 | 1,040 | 1,492 | 1,255 | ||||||||||||
Deferred income taxes | — | 85 | 517 | 1 | ||||||||||||
Regulatory liabilities | 60 | 44 | 335 | 197 | ||||||||||||
Dividends payable | 472 | 349 | ||||||||||||||
Mark-to-market derivative liabilities | 52 | 38 | 1,105 | 112 | ||||||||||||
Unamortized energy contract liabilities | 707 | — | ||||||||||||||
Other | 498 | 836 | 862 | 560 | ||||||||||||
|
|
|
| |||||||||||||
Total current liabilities | 4,977 | 4,240 | 9,052 | 5,134 | ||||||||||||
|
|
|
| |||||||||||||
Long-term debt | 12,175 | 11,614 | 16,293 | 11,799 | ||||||||||||
Long-term debt to financing trusts | 390 | 390 | 648 | 390 | ||||||||||||
Long-term debt of variable interest entity | 517 | — | ||||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Deferred income taxes and unamortized investment tax credits | 7,958 | 6,621 | 10,705 | 8,253 | ||||||||||||
Asset retirement obligations | 3,808 | 3,494 | 4,064 | 3,884 | ||||||||||||
Pension obligations | 1,475 | 3,658 | 2,553 | 2,194 | ||||||||||||
Non-pension postretirement benefit obligations | 2,371 | 2,218 | 2,688 | 2,263 | ||||||||||||
Spent nuclear fuel obligation | 1,019 | 1,018 | 1,019 | 1,019 | ||||||||||||
Regulatory liabilities | 3,601 | 3,555 | 4,050 | 3,627 | ||||||||||||
Mark-to-market derivative liabilities | 79 | 21 | 671 | 126 | ||||||||||||
Unamortized energy contract liabilities | 897 | — | ||||||||||||||
Payable for Zion Station decommissioning | 604 | 659 | 574 | 563 | ||||||||||||
Other | 1,253 | 1,102 | 1,708 | 1,268 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred credits and other liabilities | 22,168 | 22,346 | 28,929 | 23,197 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities | 39,710 | 38,590 | 55,439 | 40,520 | ||||||||||||
|
|
|
| |||||||||||||
Commitments and contingencies | ||||||||||||||||
Preferred securities of subsidiary | 87 | 87 | 87 | 87 | ||||||||||||
Shareholders’ equity | ||||||||||||||||
Common stock (No par value, 2,000 shares authorized, 663 shares outstanding at September 30, 2011 and 662 shares outstanding at December 31, 2010, respectively) | 9,077 | 9,006 | ||||||||||||||
Treasury stock, at cost (35 shares at September 30, 2011 and December 31, 2010, respectively) | (2,327 | ) | (2,327 | ) | ||||||||||||
Common stock (No par value, 2,000 shares authorized, 852 shares and 663 shares outstanding at March 31, 2012 and December 31, 2011, respectively) | 16,512 | 9,107 | ||||||||||||||
Treasury stock, at cost (35 shares at March 31, 2012 and December 31, 2011, respectively) | (2,327 | ) | (2,327 | ) | ||||||||||||
Retained earnings | 10,146 | 9,304 | 9,830 | 10,055 | ||||||||||||
Accumulated other comprehensive loss, net | (2,540 | ) | (2,423 | ) | (2,199 | ) | (2,450 | ) | ||||||||
|
|
|
| |||||||||||||
Total shareholders’ equity | 14,356 | 13,560 | 21,816 | 14,385 | ||||||||||||
BGE preference stock not subject to mandatory redemption | 193 | — | ||||||||||||||
Noncontrolling interest | 3 | 3 | 93 | 3 | ||||||||||||
|
|
|
| |||||||||||||
Total equity | 14,359 | 13,563 | 22,102 | 14,388 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities and shareholders’ equity | $ | 54,156 | $ | 52,240 | $ | 77,628 | $ | 54,995 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(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 | — | — | — | 1,889 | — | — | 1,889 | |||||||||||||||||||||
Long-term incentive plan activity | 1,167 | 71 | — | — | — | — | 71 | |||||||||||||||||||||
Common stock dividends | — | — | — | (1,047 | ) | — | — | (1,047 | ) | |||||||||||||||||||
Other comprehensive loss net of income taxes of $72 | — | — | — | — | (117 | ) | — | (117 | ) | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Balance, September 30, 2011 | 697,756 | $ | 9,077 | $ | (2,327 | ) | $ | 10,146 | $ | (2,540 | ) | $ | 3 | $ | 14,359 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions, shares in thousands) | Issued Shares | Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Loss, net | Non-controlling Interest | BGE preference stock not subject to mandatory redemption | Total Equity | ||||||||||||||||||||||||
Balance, December 31, 2011 | 698,112 | $ | 9,107 | $ | (2,327 | ) | $ | 10,055 | $ | (2,450 | ) | $ | 3 | $ | — | $ | 14,388 | |||||||||||||||
Net income | — | — | — | 202 | — | (2 | ) | — | 200 | |||||||||||||||||||||||
Long-term incentive plan activity | 917 | 40 | — | — | — | — | — | 40 | ||||||||||||||||||||||||
Common stock dividends | — | — | — | (425 | ) | — | — | — | (425 | ) | ||||||||||||||||||||||
Common stock issuance — Constellation merger | 188,124 | 7,365 | — | — | — | — | — | 7,365 | ||||||||||||||||||||||||
Acquisition of Constellation | — | — | — | — | — | 92 | 193 | 285 | ||||||||||||||||||||||||
Preferred and preference stock dividends | — | — | — | (2 | ) | — | — | — | (2 | ) | ||||||||||||||||||||||
Other comprehensive income net of income taxes of $(228) | — | — | — | — | 251 | — | — | 251 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Balance, March 31, 2012 | 887,153 | $ | 16,512 | $ | (2,327 | ) | $ | 9,830 | $ | (2,199 | ) | $ | 93 | $ | 193 | $ | 22,102 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(In millions) | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Operating revenues | ||||||||||||||||
Operating revenues | $ | 2,558 | $ | 1,877 | $ | 7,291 | $ | 5,098 | ||||||||
Operating revenues from affiliates | 304 | 778 | 856 | 2,330 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total operating revenues | 2,862 | 2,655 | 8,147 | 7,428 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Operating expenses | ||||||||||||||||
Purchased power | 680 | 494 | 1,801 | 1,251 | ||||||||||||
Fuel | 432 | 451 | 1,222 | 1,191 | ||||||||||||
Operating and maintenance | 713 | 580 | 2,084 | 1,865 | ||||||||||||
Operating and maintenance from affiliates | 77 | 69 | 222 | 216 | ||||||||||||
Depreciation and amortization | 139 | 121 | 416 | 344 | ||||||||||||
Taxes other than income | 67 | 57 | 199 | 175 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total operating expenses | 2,108 | 1,772 | 5,944 | 5,042 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Operating income | 754 | 883 | 2,203 | 2,386 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (37 | ) | (37 | ) | (128 | ) | (109 | ) | ||||||||
Other, net | (164 | ) | 192 | (12 | ) | 138 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total other income and deductions | (201 | ) | 155 | (140 | ) | 29 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Income before income taxes | 553 | 1,038 | 2,063 | 2,415 | ||||||||||||
Income taxes | 167 | 433 | 738 | 867 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Net income | 386 | 605 | 1,325 | 1,548 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||
Change in unrealized gain (loss) on cash flow hedges | (125 | ) | 292 | (448 | ) | 298 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Other comprehensive income (loss) | (125 | ) | 292 | (448 | ) | 298 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Comprehensive income | $ | 261 | $ | 897 | $ | 877 | $ | 1,846 | ||||||||
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWSOPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Nine Months Ended September 30, | ||||||||
(In millions) | 2011 | 2010 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 1,325 | $ | 1,548 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion, including nuclear fuel amortization | 1,131 | 987 | ||||||
Deferred income taxes and amortization of investment tax credits | 336 | 409 | ||||||
Net fair value changes related to derivatives | 360 | (281 | ) | |||||
Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments | 90 | (49 | ) | |||||
Other non-cash operating activities | 362 | 164 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (165 | ) | (11 | ) | ||||
Receivables from and payables to affiliates, net | 210 | 76 | ||||||
Inventories | (32 | ) | (50 | ) | ||||
Accounts payable, accrued expenses and other current liabilities | (1 | ) | (162 | ) | ||||
Option premiums received (paid), net | 59 | (101 | ) | |||||
Counterparty collateral (paid) received, net | (804 | ) | 443 | |||||
Income taxes | 268 | (13 | ) | |||||
Pension and non-pension postretirement benefit contributions | (952 | ) | (345 | ) | ||||
Other assets and liabilities | (65 | ) | (52 | ) | ||||
|
|
|
| |||||
Net cash flows provided by operating activities | 2,122 | 2,563 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (1,865 | ) | (1,405 | ) | ||||
Proceeds from nuclear decommissioning trust fund sales | 3,120 | 2,756 | ||||||
Investment in nuclear decommissioning trust funds | (3,293 | ) | (2,864 | ) | ||||
Acquisitions | (380 | ) | — | |||||
Change in restricted cash | — | 3 | ||||||
Other investing activities | (3 | ) | 9 | |||||
|
|
|
| |||||
Net cash flows used in investing activities | (2,421 | ) | (1,501 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term debt | 72 | — | ||||||
Issuance of long-term debt | — | 898 | ||||||
Retirement of long-term debt | (2 | ) | (214 | ) | ||||
Distribution to member | (61 | ) | (623 | ) | ||||
Contribution from member | 30 | 3 | ||||||
Other financing activities | (53 | ) | (16 | ) | ||||
|
|
|
| |||||
Net cash flows (used in) provided by financing activities | (14 | ) | 48 | |||||
|
|
|
| |||||
(Decrease) increase in cash and cash equivalents | (313 | ) | 1,110 | |||||
Cash and cash equivalents at beginning of period | 456 | 1,099 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 143 | $ | 2,209 | ||||
|
|
|
|
Three Months Ended March 31, | ||||||||
(In millions) | 2012 | 2011 | ||||||
Operating revenues | ||||||||
Operating revenues | $ | 2,373 | $ | 2,337 | ||||
Operating revenues from affiliates | 366 | 306 | ||||||
|
|
|
| |||||
Total operating revenues | 2,739 | 2,643 | ||||||
|
|
|
| |||||
Operating expenses | ||||||||
Purchased power and fuel | 1,044 | 883 | ||||||
Operating and maintenance | 1,039 | 680 | ||||||
Operating and maintenance from affiliates | 136 | 74 | ||||||
Depreciation and amortization | 153 | 139 | ||||||
Taxes other than income | 73 | 66 | ||||||
|
|
|
| |||||
Total operating expenses | 2,445 | 1,842 | ||||||
|
|
|
| |||||
Equity in loss of unconsolidated affiliates | (22 | ) | — | |||||
Operating income | 272 | 801 | ||||||
|
|
|
| |||||
Other income and deductions | ||||||||
Interest expense | (54 | ) | (45 | ) | ||||
Other, net | 178 | 75 | ||||||
|
|
|
| |||||
Total other income and deductions | 124 | 30 | ||||||
|
|
|
| |||||
Income before income taxes | 396 | 831 | ||||||
Income taxes | 230 | 336 | ||||||
|
|
|
| |||||
Net income | 166 | 495 | ||||||
Net loss attributable to noncontrolling interests | (2 | ) | — | |||||
|
|
|
| |||||
Net income on membership interest | 168 | 495 | ||||||
|
|
|
| |||||
Other comprehensive income (loss), net of income taxes | ||||||||
Change in unrealized gain (loss) on cash flow hedges | 252 | (70 | ) | |||||
|
|
|
| |||||
Other comprehensive income (loss) | 252 | (70 | ) | |||||
|
|
|
| |||||
Comprehensive income | $ | 420 | $ | 425 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETSSTATEMENTS OF CASH FLOWS
(Unaudited)
(In millions) | September 30, 2011 | December 31, 2010 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 143 | $ | 456 | ||||
Restricted cash and cash equivalents | 1 | 1 | ||||||
Accounts receivable, net | ||||||||
Customer | 592 | 469 | ||||||
Other | 219 | 161 | ||||||
Mark-to-market derivative assets | 478 | 487 | ||||||
Mark-to-market derivative assets with affiliates | 417 | 455 | ||||||
Receivables from affiliates | 95 | 306 | ||||||
Inventories, net | ||||||||
Fossil fuel | 117 | 129 | ||||||
Materials and supplies | 546 | 500 | ||||||
Other | 171 | 123 | ||||||
|
|
|
| |||||
Total current assets | 2,779 | 3,087 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 13,042 | 11,662 | ||||||
Deferred debits and other assets | ||||||||
Nuclear decommissioning trust funds | 6,226 | 6,408 | ||||||
Investments | 38 | 35 | ||||||
Mark-to-market derivative assets | 285 | 391 | ||||||
Mark-to-market derivative assets with affiliates | 247 | 525 | ||||||
Prepaid pension asset | 2,097 | 1,236 | ||||||
Pledged assets for Zion Station decommissioning | 763 | 824 | ||||||
Other | 609 | 366 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 10,265 | 9,785 | ||||||
|
|
|
| |||||
Total assets | $ | 26,086 | $ | 24,534 | ||||
|
|
|
|
Three Months Ended March 31, | ||||||||
(In millions) | 2012 | 2011 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 166 | $ | 495 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization | 547 | 364 | ||||||
Deferred income taxes and amortization of investment tax credits | 165 | 180 | ||||||
Net fair value changes related to derivatives | (63 | ) | 148 | |||||
Net realized and unrealized gains on nuclear decommissioning trust fund investments | (103 | ) | (40 | ) | ||||
Other non-cash operating activities | 90 | 72 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 321 | (151 | ) | |||||
Receivables from and payables to affiliates, net | 85 | 238 | ||||||
Inventories | 59 | 26 | ||||||
Accounts payable, accrued expenses and other current liabilities | (782 | ) | 17 | |||||
Option premiums (paid) received, net | (100 | ) | 19 | |||||
Counterparty collateral received (paid), net | 348 | (206 | ) | |||||
Income taxes | 162 | 388 | ||||||
Pension and non-pension postretirement benefit contributions | (20 | ) | (952 | ) | ||||
Other assets and liabilities | (80 | ) | (20 | ) | ||||
|
|
|
| |||||
Net cash flows provided by operating activities | 795 | 578 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (1,055 | ) | (772 | ) | ||||
Proceeds from nuclear decommissioning trust fund sales | 3,680 | 1,195 | ||||||
Investment in nuclear decommissioning trust funds | (3,726 | ) | (1,247 | ) | ||||
Change in restricted cash | (1 | ) | — | |||||
Cash acquired from Constellation | 708 | — | ||||||
Other investing activities | (77 | ) | 1 | |||||
|
|
|
| |||||
Net cash flows used in investing activities | (471 | ) | (823 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Retirement of long-term debt | (1 | ) | (1 | ) | ||||
Distribution to member | (600 | ) | — | |||||
Other financing activities | — | (37 | ) | |||||
|
|
|
| |||||
Net cash flows used in financing activities | (601 | ) | (38 | ) | ||||
|
|
|
| |||||
Decrease in cash and cash equivalents | (277 | ) | (283 | ) | ||||
Cash and cash equivalents at beginning of period | 496 | 456 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 219 | $ | 173 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
(In millions) | March 31, 2012 | December 31, 2011 | ||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 219 | $ | 496 | ||||
Restricted cash and cash equivalents | 3 | 5 | ||||||
Restricted cash and cash equivalents, variable interest entities | 18 | — | ||||||
Accounts receivable, net | ||||||||
Customer | 1,520 | 578 | ||||||
Other | 404 | 257 | ||||||
Accounts receivable, net, variable interest entities | 241 | — | ||||||
Mark-to-market derivative assets | 1,491 | 432 | ||||||
Mark-to-market derivative assets with affiliates | 590 | 503 | ||||||
Receivables from affiliates | 142 | 109 | ||||||
Unamortized energy contract assets | 1,699 | 13 | ||||||
Inventories, net | ||||||||
Fossil fuel | 132 | 120 | ||||||
Materials and supplies | 602 | 556 | ||||||
Other | 1,180 | 148 | ||||||
|
|
|
| |||||
Total current assets | 8,241 | 3,217 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 17,480 | 13,475 | ||||||
Deferred debits and other assets | ||||||||
Nuclear decommissioning trust funds | 6,927 | 6,507 | ||||||
Investments | 70 | 41 | ||||||
Investments in affiliates | 340 | 1 | ||||||
Investment in CENG | 2,046 | — | ||||||
Mark-to-market derivative assets | 1,375 | 635 | ||||||
Mark-to-market derivative assets with affiliates | 92 | 191 | ||||||
Prepaid pension asset | 2,098 | 2,068 | ||||||
Pledged assets for Zion Station decommissioning | 708 | 734 | ||||||
Unamortized energy contract assets | 1,530 | 388 | ||||||
Other | 816 | 176 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 16,002 | 10,741 | ||||||
|
|
|
| |||||
Total assets | $ | 41,723 | $ | 27,433 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2011 | December 31, 2010 | March 31, 2012 | December 31, 2011 | ||||||||||||
(Unaudited) | ||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term borrowings | $ | 72 | $ | — | $ | 114 | $ | 2 | ||||||||
Long-term debt due within one year | 3 | 3 | 72 | 3 | ||||||||||||
Accounts payable | 746 | 749 | 1,229 | 753 | ||||||||||||
Accounts payable of variable interest entities | 138 | — | ||||||||||||||
Accrued expenses | 676 | 391 | 894 | 779 | ||||||||||||
Payables to affiliates | 47 | 47 | 183 | 58 | ||||||||||||
Deferred income taxes | 153 | 427 | 758 | 244 | ||||||||||||
Mark-to-market derivative liabilities | 49 | 34 | 1,090 | 103 | ||||||||||||
Unamortized energy contract liabilities | 590 | — | ||||||||||||||
Other | 161 | 192 | 360 | 202 | ||||||||||||
|
|
|
| |||||||||||||
Total current liabilities | 1,907 | 1,843 | 5,428 | 2,144 | ||||||||||||
|
|
|
| |||||||||||||
Long-term debt | 3,674 | 3,676 | 6,388 | 3,674 | ||||||||||||
Long-term debt of variable interest entities | 186 | — | ||||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Deferred income taxes and unamortized investment tax credits | 3,635 | 3,318 | 4,899 | 3,966 | ||||||||||||
Asset retirement obligations | 3,691 | 3,357 | 3,939 | 3,767 | ||||||||||||
Non-pension postretirement benefit obligations | 788 | 692 | 778 | 703 | ||||||||||||
Spent nuclear fuel obligation | 1,019 | 1,018 | 1,019 | 1,019 | ||||||||||||
Payables to affiliates | 2,078 | 2,267 | 2,430 | 2,222 | ||||||||||||
Mark-to-market derivative liabilities | 31 | 21 | 546 | 29 | ||||||||||||
Unamortized energy contract liabilities | 808 | — | ||||||||||||||
Payable for Zion Station decommissioning | 604 | 659 | 574 | 563 | ||||||||||||
Other | 636 | 506 | 839 | 638 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred credits and other liabilities | 12,482 | 11,838 | 15,832 | 12,907 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities | 18,063 | 17,357 | 27,834 | 18,725 | ||||||||||||
|
|
|
| |||||||||||||
Commitments and contingencies | ||||||||||||||||
Equity | ||||||||||||||||
Member’s equity | ||||||||||||||||
Membership interest | 3,556 | 3,526 | 8,828 | 3,556 | ||||||||||||
Undistributed earnings | 3,897 | 2,633 | 3,800 | 4,232 | ||||||||||||
Accumulated other comprehensive income, net | 565 | 1,013 | 1,167 | 915 | ||||||||||||
|
|
|
| |||||||||||||
Total member’s equity | 8,018 | 7,172 | 13,795 | 8,703 | ||||||||||||
Noncontrolling interest | 5 | 5 | 94 | 5 | ||||||||||||
|
|
|
| |||||||||||||
Total equity | 8,023 | 7,177 | 13,889 | 8,708 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities and equity | $ | 26,086 | $ | 24,534 | $ | 41,723 | $ | 27,433 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
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 | — | 1,325 | — | — | 1,325 | |||||||||||||||
Allocation of tax benefit from member | 30 | — | — | — | 30 | |||||||||||||||
Distribution to member | — | (61 | ) | — | — | (61 | ) | |||||||||||||
Other comprehensive loss, net of income taxes of $293 | — | — | (448 | ) | — | (448 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance, September 30, 2011 | $ | 3,556 | $ | 3,897 | $ | 565 | $ | 5 | $ | 8,023 | ||||||||||
|
|
|
|
|
|
|
|
|
|
Member’s Equity | ||||||||||||||||||||
(In millions) | Membership Interest | Undistributed Earnings | Accumulated Other Comprehensive Income, net | Noncontrolling Interest | Total Equity | |||||||||||||||
Balance, December 31, 2011 | $ | 3,556 | $ | 4,232 | $ | 915 | $ | 5 | $ | 8,708 | ||||||||||
Net income | — | 168 | — | (2 | ) | 166 | ||||||||||||||
Acquisition of Constellation | 5,272 | — | — | 91 | 5,363 | |||||||||||||||
Distribution to member | — | (600 | ) | — | — | (600 | ) | |||||||||||||
Other comprehensive income, net of income taxes of $(166) | — | — | 252 | — | 252 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance, March 31, 2012 | $ | 8,828 | $ | 3,800 | $ | 1,167 | $ | 94 | $ | 13,889 | ||||||||||
|
|
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(In millions) | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Operating revenues | ||||||||||||||||
Operating revenues | $ | 1,783 | $ | 1,918 | $ | 4,692 | $ | 4,831 | ||||||||
Operating revenues from affiliates | 1 | — | 2 | 1 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total operating revenues | 1,784 | 1,918 | 4,694 | 4,832 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Operating expenses | ||||||||||||||||
Purchased power | 773 | 910 | 1,986 | 1,810 | ||||||||||||
Purchased power from affiliate | 159 | 202 | 450 | 826 | ||||||||||||
Operating and maintenance | 313 | 260 | 733 | 620 | ||||||||||||
Operating and maintenance from affiliate | 40 | 38 | 113 | 113 | ||||||||||||
Operating and maintenance for regulatory required programs | 43 | 22 | 84 | 62 | ||||||||||||
Depreciation and amortization | 135 | 126 | 405 | 386 | ||||||||||||
Taxes other than income | 78 | 81 | 226 | 188 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total operating expenses | 1,541 | 1,639 | 3,997 | 4,005 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Operating income | 243 | 279 | 697 | 827 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (82 | ) | (79 | ) | (246 | ) | (290 | ) | ||||||||
Interest expense to affiliates, net | (4 | ) | (3 | ) | (11 | ) | (10 | ) | ||||||||
Other, net | 16 | 3 | 24 | 14 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total other income and deductions | (70 | ) | (79 | ) | (233 | ) | (286 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Income before income taxes | 173 | 200 | 464 | 541 | ||||||||||||
Income taxes | 61 | 79 | 169 | 295 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Net income | 112 | 121 | 295 | 246 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Other comprehensive income, net of income taxes | ||||||||||||||||
Change in unrealized gain on cash flow hedges | — | 4 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Other comprehensive income | — | 4 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Comprehensive income | $ | 112 | $ | 125 | $ | 295 | $ | 246 | ||||||||
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWSOPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Nine Months Ended September 30, | ||||||||
(In millions) | 2011 | 2010 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 295 | $ | 246 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 405 | 387 | ||||||
Deferred income taxes and amortization of investment tax credits | 527 | 199 | ||||||
Other non-cash operating activities | 210 | 162 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (4 | ) | (72 | ) | ||||
Receivables from and payables to affiliates, net | (13 | ) | (69 | ) | ||||
Inventories | (11 | ) | (2 | ) | ||||
Accounts payable, accrued expenses and other current liabilities | (160 | ) | 224 | |||||
Counterparty collateral paid, net | (3 | ) | (154 | ) | ||||
Income taxes | 211 | 61 | ||||||
Pension and non-pension postretirement benefit contributions | (871 | ) | (254 | ) | ||||
Other assets and liabilities | 29 | (86 | ) | |||||
|
|
|
| |||||
Net cash flows provided by operating activities | 615 | 642 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (758 | ) | (686 | ) | ||||
Change in restricted cash | (536 | ) | — | |||||
Other investing activities | 18 | 16 | ||||||
|
|
|
| |||||
Net cash flows used in investing activities | (1,276 | ) | (670 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term debt | — | (90 | ) | |||||
Issuance of long-term debt | 1,199 | 500 | ||||||
Retirement of long-term debt | (1 | ) | (213 | ) | ||||
Contributions from parent | — | 2 | ||||||
Dividends paid on common stock | (225 | ) | (225 | ) | ||||
Other financing activities | (6 | ) | (3 | ) | ||||
|
|
|
| |||||
Net cash flows provided by (used in) financing activities | 967 | (29 | ) | |||||
|
|
|
| |||||
Increase (Decrease) in cash and cash equivalents | 306 | (57 | ) | |||||
Cash and cash equivalents at beginning of period | 50 | 91 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 356 | $ | 34 | ||||
|
|
|
|
Three Months Ended March 31, | ||||||||
(In millions) | 2012 | 2011 | ||||||
Operating revenues | ||||||||
Operating revenues | $ | 1,387 | $ | 1,465 | ||||
Operating revenues from affiliates | 1 | 1 | ||||||
|
|
|
| |||||
Total operating revenues | 1,388 | 1,466 | ||||||
|
|
|
| |||||
Operating expenses | ||||||||
Purchased power | 373 | 626 | ||||||
Purchased power from affiliate | 247 | 163 | ||||||
Operating and maintenance | 276 | 229 | ||||||
Operating and maintenance from affiliate | 42 | 37 | ||||||
Depreciation and amortization | 149 | 134 | ||||||
Taxes other than income | 75 | 77 | ||||||
|
|
|
| |||||
Total operating expenses | 1,162 | 1,266 | ||||||
|
|
|
| |||||
Operating income | 226 | 200 | ||||||
|
|
|
| |||||
Other income and deductions | ||||||||
Interest expense | (79 | ) | (82 | ) | ||||
Interest expense to affiliates, net | (3 | ) | (3 | ) | ||||
Other, net | 4 | 4 | ||||||
|
|
|
| |||||
Total other income and deductions | (78 | ) | (81 | ) | ||||
|
|
|
| |||||
Income before income taxes | 148 | 119 | ||||||
Income taxes | 61 | 50 | ||||||
|
|
|
| |||||
Net income | 87 | 69 | ||||||
Other comprehensive income, net of income taxes | ||||||||
Change in unrealized gain on marketable securities | 1 | — | ||||||
|
|
|
| |||||
Other comprehensive income | 1 | — | ||||||
Comprehensive income | $ | 88 | $ | 69 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETSSTATEMENTS OF CASH FLOWS
(Unaudited)
(In millions) | September 30, 2011 | December 31, 2010 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 356 | $ | 50 | ||||
Restricted cash | 539 | — | ||||||
Accounts receivable, net | ||||||||
Customer | 697 | 768 | ||||||
Other | 372 | 525 | ||||||
Inventories, net | 83 | 72 | ||||||
Deferred income taxes | 84 | 115 | ||||||
Counterparty collateral deposited | 159 | 153 | ||||||
Regulatory assets | 441 | 456 | ||||||
Other | 21 | 12 | ||||||
|
|
|
| |||||
Total current assets | 2,752 | 2,151 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 12,955 | 12,578 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 733 | 947 | ||||||
Investments | 21 | 23 | ||||||
Investments in affiliates | 6 | 6 | ||||||
Goodwill | 2,625 | 2,625 | ||||||
Receivables from affiliates | 1,751 | 1,895 | ||||||
Mark-to-market derivative assets | — | 4 | ||||||
Prepaid pension asset | 1,829 | 1,039 | ||||||
Other | 311 | 384 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 7,276 | 6,923 | ||||||
|
|
|
| |||||
Total assets | $ | 22,983 | $ | 21,652 | ||||
|
|
|
|
Three Months Ended March 31, | ||||||||
(In millions) | 2012 | 2011 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 87 | $ | 69 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 149 | 134 | ||||||
Deferred income taxes and amortization of investment tax credits | 57 | 81 | ||||||
Other non-cash operating activities | 60 | 82 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 58 | 21 | ||||||
Receivables from and payables to affiliates, net | 15 | (22 | ) | |||||
Inventories | (3 | ) | (4 | ) | ||||
Accounts payable, accrued expenses and other current liabilities | (159 | ) | (153 | ) | ||||
Counterparty collateral (paid) received, net | (8 | ) | 56 | |||||
Income taxes | 116 | 288 | ||||||
Pension and non-pension postretirement benefit contributions | (9 | ) | (871 | ) | ||||
Other assets and liabilities | (72 | ) | (35 | ) | ||||
|
|
|
| |||||
Net cash flows provided by (used in) operating activities | 291 | (354 | ) | |||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (291 | ) | (251 | ) | ||||
Proceeds from sales of investments | 10 | 1 | ||||||
Purchases of investments | (5 | ) | (1 | ) | ||||
Other investing activities | 6 | 10 | ||||||
|
|
|
| |||||
Net cash flows used in investing activities | (280 | ) | (241 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term debt | 302 | 50 | ||||||
Issuance of long-term debt | — | 599 | ||||||
Retirement of long-term debt | (450 | ) | — | |||||
Dividends paid on common stock | (75 | ) | (75 | ) | ||||
Other financing activities | (3 | ) | (2 | ) | ||||
|
|
|
| |||||
Net cash flows (used in) provided by financing activities | (226 | ) | 572 | |||||
|
|
|
| |||||
Decrease in cash and cash equivalents | (215 | ) | (23 | ) | ||||
Cash and cash equivalents at beginning of period | 234 | 50 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 19 | $ | 27 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
(In millions) | March 31, 2012 | December 31, 2011 | ||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 19 | $ | 234 | ||||
Restricted cash | 3 | 3 | ||||||
Accounts receivable, net | ||||||||
Customer | 596 | 655 | ||||||
Other | 272 | 385 | ||||||
Inventories, net | 84 | 81 | ||||||
Deferred income taxes | 62 | 61 | ||||||
Counterparty collateral deposited | 98 | 90 | ||||||
Regulatory assets | 793 | 657 | ||||||
Other | 21 | 22 | ||||||
|
|
|
| |||||
Total current assets | 1,948 | 2,188 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 13,267 | 13,121 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 644 | 699 | ||||||
Investments | 16 | 21 | ||||||
Investments in affiliates | 6 | 6 | ||||||
Goodwill | 2,625 | 2,625 | ||||||
Receivables from affiliates | 2,020 | 1,860 | ||||||
Prepaid pension asset | 1,772 | 1,803 | ||||||
Other | 291 | 315 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 7,374 | 7,329 | ||||||
|
|
|
| |||||
Total assets | $ | 22,589 | $ | 22,638 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2011 | December 31, 2010 | March 31, 2012 | December 31, 2011 | ||||||||||||
(Unaudited) | ||||||||||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term borrowings | $ | 302 | $ | — | ||||||||||||
Long-term debt due within one year | $ | 987 | $ | 347 | — | 450 | ||||||||||
Accounts payable | 305 | 332 | 277 | 325 | ||||||||||||
Accrued expenses | 234 | 366 | 204 | 318 | ||||||||||||
Payables to affiliates | 385 | 398 | 125 | 111 | ||||||||||||
Customer deposits | 135 | 130 | 138 | 136 | ||||||||||||
Regulatory liabilities | 17 | 19 | 127 | 137 | ||||||||||||
Mark-to-market derivative liability | 16 | 9 | ||||||||||||||
Mark-to-market derivative liability with affiliate | 415 | 450 | 590 | 503 | ||||||||||||
Other | 75 | 92 | 69 | 82 | ||||||||||||
|
|
|
| |||||||||||||
Total current liabilities | 2,553 | 2,134 | 1,848 | 2,071 | ||||||||||||
|
|
|
| |||||||||||||
Long-term debt | 5,215 | 4,654 | 5,215 | 5,215 | ||||||||||||
Long-term debt to financing trust | 206 | 206 | 206 | 206 | ||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Deferred income taxes and unamortized investment tax credits | 3,852 | 3,308 | 4,042 | 3,993 | ||||||||||||
Asset retirement obligations | 89 | 105 | 90 | 89 | ||||||||||||
Non-pension postretirement benefits obligations | 350 | 271 | 301 | 271 | ||||||||||||
Regulatory liabilities | 3,038 | 3,137 | 3,208 | 3,042 | ||||||||||||
Mark-to-market derivative liability | 48 | — | 125 | 97 | ||||||||||||
Mark-to-market derivative liability with affiliate | 247 | 525 | 92 | 191 | ||||||||||||
Other | 405 | 402 | 403 | 426 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred credits and other liabilities | 8,029 | 7,748 | 8,261 | 8,109 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities | 16,003 | 14,742 | 15,530 | 15,601 | ||||||||||||
|
|
|
| |||||||||||||
Commitments and contingencies | ||||||||||||||||
Shareholders’ equity | ||||||||||||||||
Common stock | 1,588 | 1,588 | 1,588 | 1,588 | ||||||||||||
Other paid-in capital | 4,992 | 4,992 | 5,012 | 5,003 | ||||||||||||
Retained earnings | 401 | 331 | 459 | 447 | ||||||||||||
Accumulated other comprehensive loss, net | (1 | ) | (1 | ) | — | (1 | ) | |||||||||
|
|
|
| |||||||||||||
Total shareholders’ equity | 6,980 | 6,910 | 7,059 | 7,037 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities and shareholders’ equity | $ | 22,983 | $ | 21,652 | $ | 22,589 | $ | 22,638 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions) | Common Stock | Other Paid-In Capital | Retained Deficit Unappropriated | Retained Earnings Appropriated | Accumulated Other Comprehensive Loss, net | Total Shareholders’ Equity | 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 | ||||||||||||||||||||||||||||||||||
Balance, December 31, 2011 | $ | 1,588 | $ | 5,003 | $ | (1,639 | ) | $ | 2,086 | $ | (1 | ) | $ | 7,037 | ||||||||||||||||||||||||||||||||||
Net income | — | — | 295 | — | — | 295 | — | — | 87 | �� | — | — | 87 | |||||||||||||||||||||||||||||||||||
Appropriation of retained earnings for future dividends | — | — | (295 | ) | 295 | — | — | — | — | (87 | ) | 87 | — | — | ||||||||||||||||||||||||||||||||||
Common stock dividends | — | — | — | (225 | ) | — | (225 | ) | — | — | — | (75 | ) | — | (75 | ) | ||||||||||||||||||||||||||||||||
Allocation of tax benefit from parent | — | 9 | — | — | — | 9 | ||||||||||||||||||||||||||||||||||||||||||
Other comprehensive income, net of income taxes of $0 | — | — | — | — | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||
Balance, September 30, 2011 | $ | 1,588 | $ | 4,992 | $ | (1,639 | ) | $ | 2,040 | $ | (1 | ) | $ | 6,980 | ||||||||||||||||||||||||||||||||||
Balance, March 31, 2012 | $ | 1,588 | $ | 5,012 | $ | (1,639 | ) | $ | 2,098 | $ | — | $ | 7,059 | |||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(In millions) | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Operating revenues | ||||||||||||||||
Operating revenues | $ | 944 | $ | 1,494 | $ | 2,938 | $ | 4,216 | ||||||||
Operating revenues from affiliates | 2 | 1 | 4 | 4 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total operating revenues | 946 | 1,495 | 2,942 | 4,220 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Operating expenses | ||||||||||||||||
Purchased power | 308 | 76 | 871 | 211 | ||||||||||||
Purchased power from affiliate | 137 | 574 | 394 | 1,498 | ||||||||||||
Fuel | 19 | 23 | 241 | 278 | ||||||||||||
Operating and maintenance | 179 | 155 | 475 | 440 | ||||||||||||
Operating and maintenance from affiliates | 24 | 21 | 68 | 67 | ||||||||||||
Operating and maintenance for regulatory required programs | 16 | 15 | 54 | 36 | ||||||||||||
Depreciation and amortization | 51 | 326 | 150 | 859 | ||||||||||||
Taxes other than income | 59 | 90 | 165 | 240 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total operating expenses | 793 | 1,280 | 2,418 | 3,629 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Operating income | 153 | 215 | 524 | 591 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Other income and deductions | ||||||||||||||||
Interest expense | (31 | ) | (35 | ) | (93 | ) | (151 | ) | ||||||||
Interest expense to affiliates, net | (3 | ) | (3 | ) | (9 | ) | (9 | ) | ||||||||
Other, net | 3 | 3 | 11 | 6 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total other income and deductions | (31 | ) | (35 | ) | (91 | ) | (154 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Income before income taxes | 122 | 180 | 433 | 437 | ||||||||||||
Income taxes | 17 | 53 | 119 | 134 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Net income | 105 | 127 | 314 | 303 | ||||||||||||
Preferred security dividends | 1 | 1 | 3 | 3 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Net income on common stock | 104 | 126 | 311 | 300 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Comprehensive income, net of income taxes | ||||||||||||||||
Net income | 105 | 127 | 314 | 303 | ||||||||||||
Other comprehensive loss, net of income taxes | ||||||||||||||||
Amortization of realized gain on net settled cash flow swaps | — | — | — | (1 | ) | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Other comprehensive loss | — | — | — | (1 | ) | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Comprehensive income | $ | 105 | $ | 127 | $ | 314 | $ | 302 | ||||||||
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWSOPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Nine Months Ended September 30, | ||||||||
(In millions) | 2011 | 2010 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 314 | $ | 303 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 150 | 859 | ||||||
Deferred income taxes and amortization of investment tax credits | 181 | (405 | ) | |||||
Other non-cash operating activities | 74 | 85 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 241 | (104 | ) | |||||
Receivables from and payables to affiliates, net | (217 | ) | (12 | ) | ||||
Inventories | — | 2 | ||||||
Accounts payable, accrued expenses and other current liabilities | 24 | (20 | ) | |||||
Income taxes | 27 | 243 | ||||||
Pension and non-pension postretirement benefit contributions | (110 | ) | (68 | ) | ||||
Other assets and liabilities | (28 | ) | 36 | |||||
|
|
|
| |||||
Net cash flows provided by operating activities | 656 | 919 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (321 | ) | (358 | ) | ||||
Changes in Exelon intercompany money pool | (91 | ) | — | |||||
Change in restricted cash | (2 | ) | 412 | |||||
Other investing activities | 12 | 7 | ||||||
|
|
|
| |||||
Net cash flows (used in) provided by investing activities | (402 | ) | 61 | |||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Retirement of long-term debt of variable interest entity | — | (806 | ) | |||||
Contributions from parent | 18 | 1 | ||||||
Dividends paid on common stock | (268 | ) | (178 | ) | ||||
Dividends paid on preferred securities | (3 | ) | (3 | ) | ||||
Repayment of receivable from parent | — | 135 | ||||||
Other financing activities | (5 | ) | — | |||||
|
|
|
| |||||
Net cash flows used in financing activities | (258 | ) | (851 | ) | ||||
|
|
|
| |||||
Increase (decrease) in cash and cash equivalents | (4 | ) | 129 | |||||
Cash and cash equivalents at beginning of period | 522 | 303 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 518 | $ | 432 | ||||
|
|
|
|
Three Months Ended March 31, | ||||||||
(In millions) | 2012 | 2011 | ||||||
Operating revenues | ||||||||
Operating revenues | $ | 874 | $ | 1,152 | ||||
Operating revenues from affiliates | 1 | 1 | ||||||
|
|
|
| |||||
Total operating revenues | 875 | 1,153 | ||||||
|
|
|
| |||||
Operating expenses | ||||||||
Purchased power and fuel | 300 | 492 | ||||||
Purchased power from affiliate | 111 | 141 | ||||||
Operating and maintenance | 173 | 184 | ||||||
Operating and maintenance from affiliates | 30 | 22 | ||||||
Depreciation and amortization | 53 | 48 | ||||||
Taxes other than income | 31 | 56 | ||||||
|
|
|
| |||||
Total operating expenses | 698 | 943 | ||||||
|
|
|
| |||||
Operating income | 177 | 210 | ||||||
|
|
|
| |||||
Other income and deductions | ||||||||
Interest expense | (28 | ) | (31 | ) | ||||
Interest expense to affiliates, net | (3 | ) | (3 | ) | ||||
Other, net | 2 | 6 | ||||||
|
|
|
| |||||
Total other income and deductions | (29 | ) | (28 | ) | ||||
|
|
|
| |||||
Income before income taxes | 148 | 182 | ||||||
Income taxes | 51 | 56 | ||||||
|
|
|
| |||||
Net income | 97 | 126 | ||||||
Preferred security dividends | 1 | 1 | ||||||
|
|
|
| |||||
Net income on common stock | $ | 96 | $ | 125 | ||||
|
|
|
| |||||
Comprehensive income, net of income taxes | ||||||||
Net income | $ | 97 | $ | 126 | ||||
Other comprehensive income, net of income taxes | ||||||||
Change in unrealized gain on marketable securities | 1 | — | ||||||
|
|
|
| |||||
Other comprehensive income | 1 | — | ||||||
|
|
|
| |||||
Comprehensive income | $ | 98 | $ | 126 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETSSTATEMENTS OF CASH FLOWS
(Unaudited)
(In millions) | September 30, 2011 | December 31, 2010 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 518 | $ | 522 | ||||
Restricted cash and cash equivalents | 2 | — | ||||||
Accounts receivable, net | ||||||||
Customer ($351 and $346 gross accounts receivable pledged as collateral as of September 30, 2011 and December 31, 2010, respectively) | 396 | 695 | ||||||
Other | 277 | 277 | ||||||
Inventories, net | ||||||||
Fossil fuel | 86 | 87 | ||||||
Materials and supplies | 19 | 18 | ||||||
Deferred income taxes | 45 | 41 | ||||||
Receivable from Exelon intercompany money pool | 91 | — | ||||||
Prepaid utility taxes | 40 | — | ||||||
Regulatory assets | 7 | 9 | ||||||
Other | 43 | 21 | ||||||
|
|
|
| |||||
Total current assets | 1,524 | 1,670 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 5,796 | 5,620 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 1,233 | 968 | ||||||
Investments | 20 | 20 | ||||||
Investments in affiliates | 8 | 8 | ||||||
Receivable from affiliates | 329 | 375 | ||||||
Prepaid pension asset | 384 | 281 | ||||||
Other | 42 | 43 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 2,016 | 1,695 | ||||||
|
|
|
| |||||
Total assets | $ | 9,336 | $ | 8,985 | ||||
|
|
|
|
Three Months Ended March 31, | ||||||||
(In millions) | 2012 | 2011 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 97 | $ | 126 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 53 | 48 | ||||||
Deferred income taxes and amortization of investment tax credits | 10 | 56 | ||||||
Other non-cash operating activities | 40 | 35 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 31 | 188 | ||||||
Receivables from and payables to affiliates, net | 12 | (227 | ) | |||||
Inventories | 39 | 55 | ||||||
Accounts payable, accrued expenses and other current liabilities | (71 | ) | (26 | ) | ||||
Income taxes | 76 | 33 | ||||||
Pension and non-pension postretirement benefit contributions | (5 | ) | (110 | ) | ||||
Other assets and liabilities | (110 | ) | (162 | ) | ||||
|
|
|
| |||||
Net cash flows provided by operating activities | 172 | 16 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (96 | ) | (121 | ) | ||||
Changes in Exelon intercompany money pool | (35 | ) | (59 | ) | ||||
Change in restricted cash | (3 | ) | (2 | ) | ||||
Other investing activities | 4 | 10 | ||||||
|
|
|
| |||||
Net cash flows used in investing activities | (130 | ) | (172 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Dividends paid on common stock | (87 | ) | (111 | ) | ||||
Dividends paid on preferred securities | (1 | ) | (1 | ) | ||||
Other financing activities | — | (5 | ) | |||||
|
|
|
| |||||
Net cash flows used in financing activities | (88 | ) | (117 | ) | ||||
|
|
|
| |||||
Decrease in cash and cash equivalents | (46 | ) | (273 | ) | ||||
Cash and cash equivalents at beginning of period | 194 | 522 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 148 | $ | 249 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
(In millions) | March 31, 2012 | December 31, 2011 | ||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 148 | $ | 194 | ||||
Restricted cash and cash equivalents | 5 | 2 | ||||||
Accounts receivable, net | ||||||||
Customer ($348 and $329 gross accounts receivable pledged as collateral as of March 31, 2012 and December 31, 2011, respectively) | 333 | 380 | ||||||
Other | 293 | 376 | ||||||
Inventories, net | ||||||||
Fossil fuel | 46 | 87 | ||||||
Materials and supplies | 20 | 18 | ||||||
Deferred income taxes | 28 | 25 | ||||||
Receivable from Exelon intercompany money pool | 117 | 82 | ||||||
Prepaid utility taxes | 130 | 1 | ||||||
Regulatory assets | 48 | 39 | ||||||
Other | 43 | 39 | ||||||
|
|
|
| |||||
Total current assets | 1,211 | 1,243 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 5,924 | 5,874 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 1,217 | 1,216 | ||||||
Investments | 23 | 22 | ||||||
Investments in affiliates | 8 | 8 | ||||||
Receivable from affiliates | 413 | 365 | ||||||
Prepaid pension asset | 381 | 382 | ||||||
Other | 38 | 46 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 2,080 | 2,039 | ||||||
|
|
|
| |||||
Total assets | $ | 9,215 | $ | 9,156 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions) | March 31, 2012 | December 31, 2011 | ||||||
(Unaudited) | ||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term notes payable — accounts receivable agreement | $ | 225 | $ | 225 | ||||
Long-term debt due within one year | 375 | 375 | ||||||
Accounts payable | 213 | 262 | ||||||
Accrued expenses | 78 | 83 | ||||||
Payables to affiliates | 75 | 62 | ||||||
Customer deposits | 52 | 53 | ||||||
Regulatory liabilities | 73 | 60 | ||||||
Other | 22 | 25 | ||||||
|
|
|
| |||||
Total current liabilities | 1,113 | 1,145 | ||||||
|
|
|
| |||||
Long-term debt | 1,597 | 1,597 | ||||||
Long-term debt to financing trusts | 184 | 184 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 2,193 | 2,170 | ||||||
Asset retirement obligations | 28 | 28 | ||||||
Non-pension postretirement benefits obligations | 295 | 288 | ||||||
Regulatory liabilities | 637 | 585 | ||||||
Other | 133 | 134 | ||||||
|
|
|
| |||||
Total deferred credits and other liabilities | 3,286 | 3,205 | ||||||
|
|
|
| |||||
Total liabilities | 6,180 | 6,131 | ||||||
|
|
|
| |||||
Commitments and contingencies | ||||||||
Preferred securities | 87 | 87 | ||||||
Shareholders’ equity | ||||||||
Common stock | 2,379 | 2,379 | ||||||
Retained earnings | 568 | 559 | ||||||
Accumulated other comprehensive income, net | 1 | — | ||||||
|
|
|
| |||||
Total shareholders’ equity | 2,948 | 2,938 | ||||||
|
|
|
| |||||
Total liabilities and shareholders’ equity | $ | 9,215 | $ | 9,156 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions) | September 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 | 257 | 201 | ||||||
Accrued expenses | 99 | 95 | ||||||
Payables to affiliates | 58 | 275 | ||||||
Customer deposits | 54 | 65 | ||||||
Regulatory liabilities | 43 | 25 | ||||||
Mark-to-market derivative liabilities | 1 | 4 | ||||||
Mark-to-market derivative liabilities with affiliate | 2 | 5 | ||||||
Other | 21 | 18 | ||||||
|
|
|
| |||||
Total current liabilities | 1,010 | 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 | 2,098 | 1,823 | ||||||
Asset retirement obligations | 28 | 32 | ||||||
Non-pension postretirement benefits obligations | 310 | 292 | ||||||
Regulatory liabilities | 563 | 418 | ||||||
Other | 140 | 131 | ||||||
|
|
|
| |||||
Total deferred credits and other liabilities | 3,139 | 2,696 | ||||||
|
|
|
| |||||
Total liabilities | 6,305 | 6,015 | ||||||
|
|
|
| |||||
Commitments and contingencies | ||||||||
Preferred securities | 87 | 87 | ||||||
Shareholders’ equity | ||||||||
Common stock | 2,379 | 2,361 | ||||||
Retained earnings | 565 | 522 | ||||||
|
|
|
| |||||
Total shareholders’ equity | 2,944 | 2,883 | ||||||
|
|
|
| |||||
Total liabilities and shareholders’ equity | $ | 9,336 | $ | 8,985 | ||||
|
|
|
|
(In millions) | Common Stock | Retained Earnings | Accumulated Other Comprehensive Income, net | Total Shareholders’ Equity | ||||||||||||
Balance, December 31, 2011 | $ | 2,379 | $ | 559 | $ | — | $ | 2,938 | ||||||||
Net income | — | 97 | — | 97 | ||||||||||||
Common stock dividends | — | (87 | ) | — | (87 | ) | ||||||||||
Preferred security dividends | — | (1 | ) | — | (1 | ) | ||||||||||
Other comprehensive income, net of income taxes of $0 | — | — | 1 | 1 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Balance, March 31, 2012 | $ | 2,379 | $ | 568 | $ | 1 | $ | 2,948 | ||||||||
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGYBALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended March 31, | ||||||||
(In millions) | 2012 | 2011 | ||||||
Operating revenues | ||||||||
Operating revenues | $ | 693 | $ | 975 | ||||
Operating revenues from affiliates | 3 | 1 | ||||||
|
|
|
| |||||
Total operating revenues | 696 | 976 | ||||||
|
|
|
| |||||
Operating expenses | ||||||||
Purchased power and fuel | 293 | 487 | ||||||
Purchased power from affiliate | 92 | 57 | ||||||
Operating and maintenance | 153 | 120 | ||||||
Operating and maintenance from affiliates | 42 | 32 | ||||||
Depreciation and amortization | 79 | 77 | ||||||
Taxes other than income | 48 | 50 | ||||||
|
|
|
| |||||
Total operating expenses | 707 | 823 | ||||||
|
|
|
| |||||
Operating (loss) income | (11 | ) | 153 | |||||
|
|
|
| |||||
Other income and deductions | ||||||||
Interest expense | (41 | ) | (33 | ) | ||||
Other, net | 6 | 8 | ||||||
|
|
|
| |||||
Total other income and deductions | (35 | ) | (25 | ) | ||||
|
|
|
| |||||
(Loss) income before income taxes | (46 | ) | 128 | |||||
Income taxes | (16 | ) | 47 | |||||
|
|
|
| |||||
Net (loss) income | (30 | ) | 81 | |||||
Preference stock dividends | 3 | 3 | ||||||
|
|
|
| |||||
Net (loss) income on common stock | $ | (33 | ) | $ | 78 | |||
|
|
|
| |||||
Comprehensive (loss) income | $ | (30 | ) | $ | 81 | |||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31, | ||||||||
(In millions) | 2012 | 2011 | ||||||
Cash flows from operating activities | ||||||||
Net (loss) income | $ | (30 | ) | $ | 81 | |||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 79 | 77 | ||||||
Deferred income taxes and amortization of investment tax credits | 40 | 29 | ||||||
Other non-cash operating activities | 178 | 16 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (9 | ) | 27 | |||||
Receivables from and payables to affiliates, net | 56 | (1 | ) | |||||
Inventories | 50 | 41 | ||||||
Accounts payable, accrued expenses and other current liabilities | (60 | ) | 3 | |||||
Income taxes | (57 | ) | 56 | |||||
Pension and non-pension postretirement benefit contributions | (7 | ) | (5 | ) | ||||
Other assets and liabilities | 12 | 26 | ||||||
|
|
|
| |||||
Net cash flows provided by operating activities | 252 | 350 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (115 | ) | (136 | ) | ||||
Change in restricted cash | (19 | ) | (23 | ) | ||||
Other investing activities | (6 | ) | — | |||||
|
|
|
| |||||
Net cash flows used in investing activities | (140 | ) | (159 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Dividends paid on common stock | — | (85 | ) | |||||
Dividends paid on preference stock | (3 | ) | (3 | ) | ||||
Other financing activities | (1 | ) | (3 | ) | ||||
|
|
|
| |||||
Net cash flows used in financing activities | (4 | ) | (91 | ) | ||||
|
|
|
| |||||
Increase in cash and cash equivalents | 108 | 100 | ||||||
Cash and cash equivalents at beginning of period | 49 | 50 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 157 | $ | 150 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
(In millions) | March 31, 2012 | December 31, 2011 | ||||||
(Unaudited) | �� | |||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 157 | $ | 49 | ||||
Restricted cash and cash equivalents of variable interest entity | 49 | 30 | ||||||
Accounts receivable, net | ||||||||
Customer | 419 | 428 | ||||||
Other | 95 | 90 | ||||||
Income taxes receivable | 77 | 21 | ||||||
Inventories, net | ||||||||
Gas held in storage | 24 | 74 | ||||||
Materials and supplies | 34 | 34 | ||||||
Prepaid utility taxes | 27 | 56 | ||||||
Regulatory assets | 174 | 174 | ||||||
Other | 10 | 12 | ||||||
|
|
|
| |||||
Total current assets | 1,066 | 968 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 5,211 | 5,132 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 553 | 550 | ||||||
Investments in affiliates | 8 | 8 | ||||||
Prepaid pension asset | 504 | 514 | ||||||
Other | 27 | 33 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 1,092 | 1,105 | ||||||
|
|
|
| |||||
Total assets | $ | 7,369 | $ | 7,205 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions) | March 31, 2012 | December 31, 2011 | ||||||
(Unaudited) | ||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Long-term debt due within one year | $ | 110 | $ | 110 | ||||
Long-term debt of variable interest entity due within one year | 63 | 63 | ||||||
Accounts payable | 167 | 210 | ||||||
Accrued expenses | 113 | 148 | ||||||
Deferred income taxes | 23 | 59 | ||||||
Payables to affiliates | 102 | 41 | ||||||
Customer deposits | 82 | 84 | ||||||
Regulatory liabilities | 22 | 18 | ||||||
Residential customer rate credit regulatory liability | 113 | — | ||||||
Other | 45 | 25 | ||||||
|
|
|
| |||||
Total current liabilities | 840 | 758 | ||||||
|
|
|
| |||||
Long-term debt | 1,596 | 1,596 | ||||||
Long-term debt to financing trust | 258 | 258 | ||||||
Long-term debt of variable interest entity | 332 | 332 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 1,569 | 1,491 | ||||||
Asset retirement obligations | 8 | 1 | ||||||
Non-pension postretirement benefits obligations | 211 | 212 | ||||||
Regulatory liabilities | 205 | 200 | ||||||
Other | 82 | 56 | ||||||
|
|
|
| |||||
Total deferred credits and other liabilities | 2,075 | 1,960 | ||||||
|
|
|
| |||||
Total liabilities | 5,101 | 4,904 | ||||||
|
|
|
| |||||
Commitments and contingencies | ||||||||
Shareholders’ equity | ||||||||
Common stock | 1,294 | 1,294 | ||||||
Retained earnings | 784 | 817 | ||||||
|
|
|
| |||||
Total shareholders’ equity | 2,078 | 2,111 | ||||||
|
|
|
| |||||
Preference stock not subject to mandatory redemption | 190 | 190 | ||||||
|
|
|
| |||||
Total equity | 2,268 | 2,301 | ||||||
|
|
|
| |||||
Total liabilities and shareholders’ equity | $ | 7,369 | $ | 7,205 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions) | Common Stock | Retained Earnings | Total Shareholders’ Equity | |||||||||
Balance, December 31, 2010 | $ | 2,361 | $ | 522 | $ | 2,883 | ||||||
Net income | — | 314 | 314 | |||||||||
Common stock dividends | — | (268 | ) | (268 | ) | |||||||
Preferred security dividends | — | (3 | ) | (3 | ) | |||||||
Allocation of tax benefit from parent | 18 | — | 18 | |||||||||
|
|
|
|
|
| |||||||
Balance, September 30, 2011 | $ | 2,379 | $ | 565 | $ | 2,944 | ||||||
|
|
|
|
|
|
(In millions) | Common Stock | Retained Earnings | Total Shareholders’ Equity | Preference stock not subject to mandatory redemption | Total Equity | |||||||||||||||
Balance, December 31, 2011 | $ | 1,294 | $ | 817 | $ | 2,111 | $ | 190 | $ | 2,301 | ||||||||||
Net loss | — | (30 | ) | (30 | ) | — | (30 | ) | ||||||||||||
Preference stock dividends | — | (3 | ) | (3 | ) | — | (3 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance, March 31, 2012 | $ | 1,294 | $ | 784 | $ | 2,078 | $ | 190 | $ | 2,268 | ||||||||||
|
|
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
1. Basis of Presentation (Exelon, Generation, ComEd, PECO and PECO)BGE)
Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy deliverydistribution businesses. Prior to March 12, 2012, its principal, wholly owned subsidiaries included ComEd, PECO and Generation. On March 12, 2012, in conjunction with the Agreement and Plan of Merger (the “Merger Agreement”), Constellation merged into Exelon with Exelon continuing as the surviving corporation. As a result of the merger transaction, Generation includes Constellation’s customer supply and generation businesses. BGE, formerly Constellation’s regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 3 — Merger and Acquisitions for further information regarding the merger transaction.
The energy generation business consists of the electric generating facilities, the wholesale energy marketing operations and competitive retail supply operations of Generation. includes:
• | Generation: The business consists of owned, contracted and investments in electric generating facilities and wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products, risk management services and natural gas exploration and production activities. |
The energy delivery businesses include the purchaseinclude:
• | ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago. |
• | PECO: 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 the Pennsylvania counties surrounding the City of Philadelphia. |
• | BGE: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore. |
For financial statement purposes, beginning on March 12, 2012, disclosures that solely relate to Constellation or BGE activities now also apply to Exelon, unless otherwise noted. When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures.
BGE was acquired through a transaction under common control (RF HoldCo) and Exelon did not apply push-down accounting to BGE. As a result, BGE will continue to maintain its current reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the three months ended March 31, 2012 and 2011 and the provisionfinancial position as of distributionMarch 31, 2012 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,December 31, 2011. However, for Exelon’s financial reporting, 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 Combined Notes to the Consolidated 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 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 September 30, 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 subsidiaries, either directly or indirectly, except for Exelon SHC, Inc., of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon, which is eliminated in Exelon’s consolidated financial statements; and certain Exelon Wind projects, of which Generation holds majority interests rangingreporting BGE activity from 94% to 99%, which are presented as Noncontrolling interest on Exelon’s and Generation’s Consolidated Balance Sheets.
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.March 12, 2012 through March 31, 2012.
Each of Generation’s, ComEd’s, PECO’s and PECO’sBGE’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
The accompanying consolidated financial statements as of September 30,March 31, 2012 and 2011 and 2010 and for the three and nine months then ended are unaudited but, in the opinion of the management of each of Exelon, Generation, ComEd and PECO, includeRegistrant includes all adjustments that are considered necessary for a fair presentationstatement of its respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 20102011 Consolidated Balance Sheets were taken from audited financial statements. Certain prior year amounts in Exelon’s and Generation’sBGE’s Consolidated Statements of Cash Flows, Exelon’s, Generation’s and in Exelon’s, ComEd’s and PECO’sBGE’s Consolidated Balance Sheets have been reclassified between line items forStatement of
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Operations and in Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets have been reclassified between line items for comparative purposes. The reclassifications did not affect the Registrants’ net income or cash flows from operating activities. See Note 14 — Supplemental Financial Information for further discussion of the reclassifications to Exelon’s and 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 PECOall Registrants included in ITEM 88. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their 2010respective 2011 Form 10-K.
Variable Interest Entities (Exelon, Generation, ComEd, PECO and PECO)BGE)
Consolidated Variable Interest Entities
The Registrants’ consolidated VIEs consist of:
BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, and to issue and service bonds secured by rate stabilization property;
a retail gas group formed to enter into a collateralized gas supply agreement with a third party gas supplier;
a retail power supply company;
a group of solar project limited liability companies formed to build, own, and operate solar power facilities; and
several wind projects designed to develop, construct and operate wind generation facilities.
See Note 1 and Note 4 of the 2011 Form 10-K for Constellation and BGE for further information regarding investments in VIEs.
For each of the consolidated VIEs:
The assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE. In the case of BondCo, BGE is required to remit all payments it receives from all residential customers for non-bypassable rate stabilization charges to BondCo. During the ninethree months ended September 30,March 31, 2012 and 2011, BGE remitted $20 million and $23 million, respectively, to BondCo.
Except for providing capital funding to the Registrants assessed theirsolar entities for ongoing construction of the solar power facilities and a $75 million parental guarantee to the third party gas supplier in support of the retail gas group, during the three months ended March 31, 2012, neither Exelon nor BGE:
provided any additional financial support to the VIEs;
had any contractual commitments or obligations to provide financial support to the VIEs; and
the creditors of the VIEs did not have recourse to Exelon’s or BGE’s general credit.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
At March 31, 2012, Exelon’s, Generation’s and BGE’s consolidated financial statements include the following consolidated VIEs, which were acquired as part of the merger:
March 31, 2012 | ||||||||||||
Exelon | Generation | BGE | ||||||||||
Current assets | $ | 525 | $ | 474 | $ | 50 | ||||||
Noncurrent assets | 410 | 364 | — | |||||||||
|
|
|
|
|
| |||||||
Total assets | $ | 935 | $ | 838 | $ | 50 | ||||||
|
|
|
|
|
| |||||||
Current liabilities | $ | 415 | $ | 340 | $ | 74 | ||||||
Noncurrent liabilities | 606 | 228 | 332 | |||||||||
|
|
|
|
|
| |||||||
Total liabilities | $ | 1,021 | $ | 568 | $ | 406 | ||||||
|
|
|
|
|
|
Unconsolidated Variable Interest Entities
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include three categories: (1) equity method investments, (2) energy purchase and sale contracts, and (3) fuel purchase commitments. As of the balance sheet date, the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to its involvement with VIE’sthe majority of the energy contracts and fuel purchase contracts with VIEs are predominately related to working capital accounts and generally represent the amounts owed by Exelon and Generation for the deliveries associated with the current billing cycles under the contracts. Further, Exelon and Generation have not provided or guaranteed the debt or equity support, or liquidity arrangements, performance guarantees or other commitments associated with these contracts, so there is no significant potential exposure to loss as a result of the involvement with these VIEs.
As of March 31, 2012, Exelon and Generation did have exposure to loss associated with six VIEs for which they were not the primary beneficiary; including certain equity method investments and certain energy contracts. The following table presents summary information about the unconsolidated VIE entities for which we have exposure to loss:
March 31, 2012 | Energy Contract VIEs | Equity Method Investment VIEs | Total | |||||||||
Total assets(a) | $ | 286 | $ | 350 | $ | 636 | ||||||
Total liabilities(a) | 223 | 113 | 336 | |||||||||
Registrants’ ownership interest(a) | — | 94 | 94 | |||||||||
Other ownership interests(a) | 63 | 143 | 206 | |||||||||
Registrants’ maximum exposure to loss: | ||||||||||||
Letters of credit | 14 | — | 14 | |||||||||
Carrying amount of our equity method investments | — | 76 | 76 | |||||||||
Debt and payment guarantees | — | 5 | 5 |
(a) | These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s balance sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. |
The variable interests noted above have been added as a result of the Constellation and Exelon merger. During the three months ended March 31, 2012, ComEd, PECO, BGE and legacy Generation assessed their
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
contracts and determined there were no significant changes in their variable interest,interests, primary beneficiary determinations or conclusions regarding consolidation conclusionsof VIEs from December 31, 2010. For2011. See Note 1 of the Exelon 2011 Form 10-K and Note 1 and Note 4 of the 2011 10-K for BGE for further information regarding the Registrants’ VIEs, see Note 1 of the 2010 Form 10-K.VIEs.
2. New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and PECO)BGE)
There were noThe following recently issued accounting standardsstandard was adopted by the Registrants during the period.
The following recently issued accounting standards are not yet required to be reflected in the combined consolidated financial statements of the Registrants:
Goodwill Impairment Assessments
In September 2011, the FASB issued authoritative guidance amending existing guidance on the annual assessment of goodwill for impairment. Under the revised guidance, entities assessing goodwill for impairment have the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step fair value based impairment test). If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step fair value based impairment test would be required. Otherwise, no further testing is required. The guidance is effective for Exelon and ComEd for periods beginning after December 15, 2011 and is not expected to have an impact on their consolidated financial statements.
Statement of Comprehensive Income
In June 2011, the FASB issued authoritative guidance requiring entities to present net income and other comprehensive income in a single continuous statement of comprehensive income or in two separate, but consecutive, statements. The new guidance does not change the components that are recognized in net income and the components that are recognized in other comprehensive income; however, the guidance requires reclassifications between net income and other comprehensive income to be presented at the financial statement line item level. This guidance is effective for the Registrants for periods beginning after December 15, 2011 and is required to be applied retroactively. Each of the Registrants currently presents a single statement of comprehensive income, consistent with the new guidance. The Registrants will present reclassifications at the financial statement line item level in accordance with this guidance upon adoption in 2012.
Fair Value Measurement
In May 2011, the FASB issued authoritative guidance amending existing guidance for measuring and disclosing fair value. The new guidance does not impact the fair value measurements included in the Registrants’ consolidated financial statements as of March 31, 2012. The guidance is effective for the Registrants beginning with the period ended March 31, 2012 and is required to be applied prospectively. See Note 6 – Fair Value of Financial Assets and Liabilities for disclosing information about fair value measurements. The FASB indicatedthe new disclosures.
Merger with Constellation (Exelon, Generation and BGE)
Description of Transaction
On March 12, 2012, Exelon completed the merger contemplated by the Merger Agreement, among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub) and Constellation. As a result of that for manymerger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the requirements, it does not intendInitial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation’s interest in RF Holdco LLC, which holds Constellation’s interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon’s interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF Holdco LLC, Exelon contributed to Generation certain subsidiaries, including the customer supply and generation businesses that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger.
Constellation’s shareholders received 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock outstanding as of March 12, 2012. Generally, all outstanding Constellation equity-based compensation awards were converted into Exelon equity-based compensation awards using the amendmentssame ratio. See Note 13 — Stock-Based Compensation Plans for further information.
Regulatory Matters
In December 2011, Exelon and Constellation reached a settlement with the State of Maryland and the City of Baltimore and other interested parties in connection with the regulatory proceedings related to resultthe merger that were pending before the MDPSC. As part of this settlement and the application for approval of the merger by MDPSC, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in a change to current accounting. Requiredan estimated direct investment in the State of Maryland of more than $1 billion.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
On February 17, 2012, the MDPSC approved the merger with conditions. Many of the conditions were reflective of the settlement agreements described above. The following pre-tax costs were recognized after the closing of the merger and are included in Exelon’s, Generation’s and BGE’s Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2012:
Description | Expected Payment Period | BGE | Generation | Exelon | Statement of Operations Location | |||||||||||
BGE rate credit of $100 per residential customer(a) | Q2 2012 | $ | 113 | $ | — | $ | 113 | Revenues | ||||||||
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers | 2012 to 2014 | — | — | 113.5 | O&M Expense | |||||||||||
Contribution for renewable energy, energy efficiency or related projects in Baltimore | 2012 to 2014 | — | — | 2 | O&M Expense | |||||||||||
Charitable contributions at $7 million per year for 10 years | 2012 to 2021 | 28 | 35 | 70 | O&M Expense | |||||||||||
State funding for offshore wind development projects | Q2 2012 | — | — | 32 | O&M Expense | |||||||||||
|
|
|
|
|
| |||||||||||
Total | $ | 141 | $ | 35 | $ | 330.5 | ||||||||||
|
|
|
|
|
|
(a) | Exelon will make a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction. |
In addition to these costs, the estimate of $1 billion of direct investment includes $95 million to $120 million for the requirement to cause construction of a headquarters building in Baltimore for Generation’s competitive energy businesses. The construction is expected to be completed in 2 to 3 years. The $1 billion estimate also includes $625 million for Exelon and Generation’s commitment to develop 285 — 300 MW of new generation in Maryland, expected to be completed over a period of 10 years. As of March 31, 2012, no amounts have been reflected in the Exelon or Generation consolidated financial statements for these expenditure commitments. Such costs, which are expected to be primarily capital in nature, will be recognized as incurred.
Pursuant to the MDPSC merger approval conditions, BGE is restricted from paying any dividend on its common shares through the end of 2014, is required to maintain specified minimum capital and O&M expenditure levels in 2012 and 2013, and is not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process.
Associated with certain of the regulatory approvals required for the merger, Exelon and Constellation agreed to enter into contracts to sell three Constellation generating stations located in PJM within 150 days (unless extended by DOJ) following the merger completion and will be required to complete the divestitures within 30 days after receipt of regulatory approvals. These stations, Brandon Shores and H.A. Wagner in Anne Arundel County, Maryland, and C.P. Crane in Baltimore County, Maryland, 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 October 2011, Exelon and Constellation reached a settlement with the PJM Independent Market Monitor, who had previously raised market power concerns regarding the merger. The settlement contains a number of commitments by Exelon, including limiting the universe of potential buyers of the divested assets to entities without significant market shares in the relevant PJM markets. The settlement also includes assurances about how Generation will bid its units into the PJM markets. The proposed divestiture and the settlement with the PJM Market Monitor were filed with FERC and the MDPSC and were included in their final orders approving the merger. As of March 31, 2012, these assets are classified as held for sale assets and included in the other current assets balance on Exelon’s and Generation’s Consolidated Balance Sheets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
In addition, in January 2012, Exelon and Constellation reached an agreement with EDF under which EDF withdrew its opposition to the Exelon-Constellation merger. The terms of the agreement address CENG, a joint venture between Constellation and EDF that owns and operates three nuclear facilities with five generating units in Maryland and New York. The agreement reaffirms the terms of the joint venture. The agreement did not include any exchange of monetary consideration, and Exelon does not expect the agreement will have material effect on Exelon’s and Generation’s future results of operations, financial position and cash flows.
Exelon was 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. Similar suits were also filed in the United States District Court for the District of Maryland. The suits sought to enjoin a Constellation shareholder vote on the proposed merger until all material information was disclosed and sought rescission of the proposed merger. During the third quarter of 2011, the parties to the suits reached an agreement in principle to settle the suits through additional disclosures are expandedto Constellation shareholders. During the first quarter of 2012, preliminary approval was obtained for the settlement with final approval of this agreement being set for June 20, 2012.
Accounting for the Merger Transaction
The total consideration in the merger was based on the opening price of a share of Exelon common stock on March 12, 2012 (in millions):
Number of Shares/ Awards Issued | Total Estimated Fair Value | |||||||
Issuance of Exelon common stock to Constellation shareholders and equity award holders at the exchange ratio of 0.930 shares for each share of Constellation common stock; based on the opening price of Exelon common stock on March 12, 2012 of $38.91(a) | 187.45 | $ | 7,294 | |||||
Issuance of Exelon equity awards to replace existing Constellation equity awards(b) | 11.30 | 71 | ||||||
|
| |||||||
Total purchase price | $ | 7,365 | ||||||
|
|
(a) | The number of shares issued excludes 0.7 million shares of stock that are held in a custodian account specifically for the settlement of unvested share-based restricted stock awards. The related share value is excluded from the estimated fair value as these awards have not vested and therefore are not in the purchase price. |
(b) | Includes vested Constellation stock options and restricted stock units converted at fair value to Exelon awards on March 12, 2012. The fair value of the stock options was determined using the Black-Sholes model. |
All options to purchase Constellation common stock under various equity agreements were converted into options to acquire a number of shares of Exelon common stock (as adjusted for the exchange ratio) at an option price. All Constellation unvested restricted stock awards granted prior to April 28, 2011, that were outstanding as of immediately prior to the consummation of the Merger, became vested on a pro rata basis (determined based upon the number of months from the start of the applicable restricted period to the closing of the Initial Merger) and converted into Exelon common stock at the exchange ratio in accordance with the applicable stock plan and award agreement terms. All Constellation restricted stock awards that remained unvested on a pro rata basis pursuant to the foregoing formula, and any Constellation unvested restricted stock awards granted after April 28, 2011, have been assumed by Exelon and automatically converted into shares of unvested restricted stock of Exelon at the exchange ratio. Likewise, all restricted stock units granted prior to April 28, 2011 under the new guidance, especially forConstellation Plans and outstanding immediately prior to the completion of the Initial Merger became vested on a pro rata basis (determined based upon the number of months from the start of the applicable restricted period to
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
the closing of the Initial Merger) and have been assumed by Exelon and automatically converted into a number of shares of Exelon common stock at the exchange ratio.
The fair value measurementsof Constellation’s assets acquired and liabilities assumed was determined based on significant estimates and assumptions that are categorized within Level 3judgmental in nature, including projected future cash flows (including timing); discount rates reflecting 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 duration of liabilities assumed.
The initial accounting for the merger with Constellation is not complete because the valuations necessary to assess the fair values of certain assets acquired and liabilities assumed are considered preliminary as a result of the short time period between the closing of the merger and the end of the first quarter of 2012. The allocation of the purchase price may be modified up to one year from the date of the merger, as more information is obtained about the fair value hierarchy,of assets acquired and liabilities assumed; however, Exelon expects to finalize these amounts by the end of 2012, if not sooner. The significant assets and liabilities for which quantitative information about the unobservable inputs, thepreliminary 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 ofamounts are recognized at March 31, 2012 include the fair value hierarchy for itemsof the acquired power supply contracts and fuel procurement contracts, unregulated property, plant and equipment, investments in affiliates, other investments, pension and OPEB plans, contingencies and uncertain tax positions, intangible assets and liabilities, long-term debt and accumulated deferred income tax liabilities. The preliminary amounts recognized are subject to revision until the valuations are completed and to the extent that are not measured at fair value inadditional information is obtained about the statementfacts and circumstances that existed as of financial position but for whichthe acquisition date. Any changes to the fair value assessments may affect the purchase price allocation and material changes could require the financial statements to be retroactively amended.
The preliminary purchase price allocation of the Initial Merger of Exelon with Constellation and Exelon’s contribution of certain subsidiaries of Constellation to Generation was as follows:
Preliminary Purchase Price Allocation | Exelon | Generation | ||||||
Current assets | $ | 4,944 | $ | 3,649 | ||||
Property, plant and equipment | 9,295 | 3,993 | ||||||
Unamortized energy contracts | 3,624 | 3,624 | ||||||
Other intangibles, trade name and retail relationships | 456 | 456 | ||||||
Investment in affiliates | 2,067 | 2,067 | ||||||
Pension and OPEB regulatory asset | 740 | — | ||||||
Other assets | 2,612 | 1,210 | ||||||
|
|
|
| |||||
Total assets | 23,738 | 14,999 | ||||||
|
|
|
| |||||
Current liabilities | 3,480 | 2,866 | ||||||
Unamortized energy contracts | 2,268 | 2,062 | ||||||
Long-term debt, including current maturities | 5,632 | 2,972 | ||||||
Noncontrolling interest | 85 | 85 | ||||||
Deferred credits and other liabilities and preferred securities | 4,908 | 1,742 | ||||||
|
|
|
| |||||
Total liabilities, preferred securities and noncontrolling interest | 16,373 | 9,727 | ||||||
|
|
|
| |||||
Total purchase price | $ | 7,365 | $ | 5,272 | ||||
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Intangible Assets Recorded
For the power supply and fuel contracts acquired from Constellation, the difference between the contract price and the market price at the date of the merger was recognized as either an intangible asset or liability based on whether the fuel contracts were in or out-of-the-money. The valuation of the acquired intangible assets/liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transaction was available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates / inputs include forecasted power and fuel prices and the discount rate. The fair value amounts will be amortized over the life of the contract in relation to the present value of the underlying cash flows. Amortization expense and income will be recorded through purchased power and fuel expense or operating revenues, respectively. Exelon presents separately in its Consolidated Balance Sheets the unamortized energy contract assets and liabilities for these contracts. The weighted-average amortization period is approximately 2 years.
The fair value of the Constellation trade name intangible asset was determined based on the relief from royalty method of the income approach whereby fair value is the present value of the license fees avoided by owning the assets. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the hypothetical royalty rate and the discount rate. The intangible asset will be amortized on a straight line based over an estimated 10 year useful life as amortization expense. The trade name intangible asset is included in deferred debits and other assets within Exelon’s Consolidated Balance Sheets.
The fair value of the retail relationships was determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset’s fair value is equal to the estimated future cash flows that will be earned on the current customer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the customer attrition rate and the discount rate. The intangible assets will be amortized on a straight line based over the useful life of the underlying assets averaging approximately 12 years. The retail relationships intangible assets are included in deferred debits and other assets within Exelon’s Consolidated Balance Sheets.
Exelon’s intangible assets and liabilities acquired through the merger with Constellation included in its Consolidated Balance Sheets, along with the future estimated amortization, were as follows as of March 31, 2012:
Description | Weighted Average Amortization | Gross | Accumulated Amortization | Net | Estimated amortization expense | |||||||||||||||||||||||||||||||
Remainder of 2012 | 2013 | 2014 | 2015 | 2016 | ||||||||||||||||||||||||||||||||
Unamortized energy contracts, net(a) | 1.5 | $ | 1,356 | $ | (122 | ) | $ | 1,234 | $ | 804 | $ | 340 | $ | 52 | $ | 18 | $ | (25 | ) | |||||||||||||||||
Trade name | 10.0 | 243 | (2 | ) | 241 | 22 | 24 | 24 | 24 | 24 | ||||||||||||||||||||||||||
Retail relationships | 11.8 | 213 | (1 | ) | 212 | 19 | 21 | 20 | 19 | 19 | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Total, net | $ | 1,812 | $ | (125 | ) | $ | 1,687 | $ | 845 | $ | 385 | $ | 96 | $ | 61 | $ | 18 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) | Includes the fair value of BGE’s power and gas supply contracts for which an offsetting regulatory asset was also recorded. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Current Quarter Impact of Merger
It is impracticable to determine the current quarter impact for the Constellation subsidiaries contributed down to Generation following the Upstream Merger. Upon closing of the merger, the operations of these Constellation subsidiaries were integrated into Generation’s operations and are therefore not distinguishable after the merger.
The current quarter impact of BGE on Exelon’s Statement of Operations includes operating revenues of $52 million and net loss of $65 million during three months ended March 31, 2012.
During the three months ended March 31, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $484 million, $110 million, $2 million, $7 million and $153 million, respectively. These costs are classified primarily within Operating and Maintenance Expense in their respective Consolidated Statements of Operations, with the exception of the $113 million BGE customer rate credit, which is included as a reduction to operating revenues.
Severance Costs
The Registrants have an ongoing severance plan under which, in general, the longer a terminated employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at its fair value at the communication date if there are no future service requirements, or, if future service is required to be disclosed. The Registrants are currently assessingreceive the effects this guidance may have on their consolidated financial statements. The guidance is effectivetermination benefit, ratably over the required service period.
Upon closing the merger with Constellation, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. The majority of these positions are anticipated to be corporate and Generation support positions. The estimated amount of severance payments associated with this plan are expected to be approximately $91 million, $51 million, $12 million, $6 million and $16 million for Exelon, Generation, ComEd, PECO and BGE, respectively. The number of employee position reductions at each Registrant and in total at Exelon will be finalized through completion of the post-merger integration process. As of March 31, 2012, management recorded its best estimate of severance benefits, which could be adjusted through completion of the post-merger integration process when specific employee position reductions are identified. Adjustments to obligations associated with the severance plan could be material to the Registrants’ results of operations. During the merger restructuring process, employees are being given the opportunity to nominate themselves for voluntary termination. At the discretion of management, these employees will receive benefits in accordance with the severance plan. Any BGE employee position reductions as a result of the post-merger integration will be voluntary under this self-identification process. For the three months ended March 31, 2012, the Registrants recorded the following charges associated with the anticipated employee reductions within operating and maintenance expense in their Consolidated Statements of Operations, except for periods beginningComEd and BGE:
Severance benefits(a) | Exelon | Generation | ComEd(b) | PECO | BGE(c) | |||||||||||||||
Severance charges(d) | $ | 67 | $ | 35 | $ | 9 | $ | 3 | $ | 14 | ||||||||||
Stock compensation | 8 | 5 | 1 | 1 | 1 | |||||||||||||||
Other charges(e) | 8 | 5 | 1 | 1 | 1 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total severance benefits | $ | 83 | $ | 45 | $ | 11 | $ | 5 | $ | 16 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(a) | For Generation, ComEd, PECO and BGE, amounts include charges billed through intercompany allocations. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(b) | Pursuant to EIMA, ComEd established a regulatory asset of $11 million for severance benefits costs, and the majority of these costs are expected to be recovered over a five-year period. |
(c) | Consistent with prior MDPSC precedent, BGE established a regulatory asset of $16 million for severance benefits costs, and the majority of these costs are expected to be recovered over a five-year period. |
(d) | Includes salary continuance and health and welfare severance benefits. For the three months ended March 31, 2012, amounts represent ongoing severance plan benefits. One-time termination benefits are expected to begin to be recognized in the second quarter of 2012. |
(e) | Primarily includes life insurance, employer payroll taxes, educational assistance and outplacement services. |
Cash payments under the severance plan will begin in the second quarter of 2012 and will continue through 2014. Substantially all cash payments under the plan are expected to be made by the end 2014 resulting in the completion of the merger restructuring plan. As of March 31, 2012, the obligations associated with the severance benefits costs are $83 million, $45 million, $11 million, $5 million and $16 million for Exelon, Generation, ComEd, PECO and BGE, respectively.
Pro-forma Impact of the Merger
The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon and Generation as if the merger with Constellation had taken place on January 1, 2011. The unaudited pro forma information was calculated after December 15, 2011applying Exelon’s and Generation’s accounting policies and adjusting Constellation’s results to reflect purchase accounting adjustments.
The unaudited pro forma financial information has been presented for illustrative purposes only and is requirednot necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.
Generation | Exelon | |||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Total Revenues | $ | 3,997 | $ | 4,884 | $ | 6,977 | $ | 8,002 | ||||||||
Net income attributable to Exelon | 129 | 343 | 409 | 593 | ||||||||||||
Basic Earnings Per Share | n.a. | n.a. | $ | 0.48 | $ | 0.70 | ||||||||||
Diluted Earnings Per Share | n.a. | n.a. | 0.48 | 0.70 |
Exelon and Constellation both incurred non-recurring costs directly related to be applied prospectively.the merger that have been excluded in the pro forma earnings presented above. During the three months ended March 31, 2012, Exelon and Generation incurred $144 million and $75 million, respectively, of merger and integration costs, excluding the impact of Maryland commitments. In addition, during the three months ended March 31, 2012, Exelon and Generation incurred $328 million and $35 million, respectively, related to costs incurred as part of the Maryland order approving the merger transaction as discussed above.
Other Acquisitions (Exelon and Generation)
Antelope Valley Solar Ranch One. On September 30, 2011, Generation acquired all of the interests in Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar PV project under development in northern Los Angeles County, California, from First Solar, Inc., which developed and will build, operate and maintain the project. On April 5, 2012, Antelope Valley received the first DOE–guaranteed loan advance of $69 million and terminated the put option that Generation had on the Antelope Valley project. See Note 8 — Debt and Credit Agreements for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Wind Development. As part of its plan to construct multiple wind facilities in 2012, Generation has acquired several project entities. The acquisitions are not considered material individually or in the aggregate for disclosure.
3.4. Regulatory Matters (Exelon, Generation, ComEd, PECO and PECO)BGE)
Regulatory and Legislative Proceedings (Exelon, Generation, ComEd, PECO and PECO)BGE)
Except for the matters noted below, the disclosures set forth in Note 2 of the 2010Exelon 2011 Form 10-K and Note 6 of Constellation’s and BGE’s 2011 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
Energy Infrastructure Modernization Act (Exelon and ComEd). During the fourth quarter of 2011, EIMA was passed into law and became effective for Illinois utility companies on an opt-in basis. The legislation provides for substantial capital investment over a ten-year period to modernize Illinois’ electric utility infrastructure and for greater certainty related to the recovery of costs by a utility through a pre-established formula rate tariff. On January 6, 2012, ComEd filed its Infrastructure Investment Plan with the ICC. Under the plan, ComEd will invest approximately $2.6 billion over ten years to modernize and storm-harden its distribution system and to implement smart grid technology. These investments will be incremental to ComEd’s historical level of capital expenditures. The January 6, 2012 filing with the ICC specifically included ComEd’s $233 million investment plan for 2012. On April 23, 2012, ComEd filed its initial AMI Deployment Plan with the ICC. Implementation of the investment plan began in early 2012 while smart meter installation in homes and businesses is expected to begin later in 2012, subject to a final order from the ICC regarding ComEd’s AMI Deployment Plan, which is expected during the second quarter of 2012. Additionally, ComEd will contribute $10 million per year for five years, as long as ComEd is subject to EIMA, to fund customer assistance programs for low-income customers, which amounts will not be recoverable through rates. ComEd recorded an immaterial amount of costs associated with customer assistance programs for the three months ended March 31, 2012. ComEd expects to make an initial contribution of $15 million (recognized as expense in 2011) to a new Science and Technology Innovation Trust fund later in 2012. ComEd will pay to the trust approximately $4 million annually, beginning later in 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect.
EIMA provides for a performance-based distribution formula rate tariff. On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of this initial proceeding is to establish the formula under which rates will be calculated going-forward, and the initial rate, which is expected to be lower than current rates, which will take effect within 30 days after the ICC order, which must be issued by May 31, 2012. Through an annual reconciliation process as described below, customer rates will be further adjusted effective January 2013 to provide recovery of the actual costs incurred during 2011, including recovery of and return on increases in rate base associated with capital spending under EIMA.
During the first quarter of 2012, ComEd and several intervenors filed testimony in the proceeding. The intervenors proposed various reductions to ComEd’s proposed revenues, which included changes to return on pension asset, rate base and operating expenses. On May 1, 2012, the ALJs issued a proposed order in ComEd’s formula rate tariff proceeding providing for a $146 million reduction in the revenue requirement being recovered in current rates, as opposed to ComEd’s final position supporting a $59 million reduction. The primary differences between the ALJ’s proposed order and ComEd’s final position relate to different approaches to
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
allocating certain costs and differences in timing or rate recovery mechanisms for various costs. The ALJs propose the use of average annual rate base and capital structure amounts (as opposed to year-end amounts as proposed by ComEd) and lower carrying costs on future reconciliation amounts. If approved by the ICC, the revenue requirement reduction as proposed by the ALJs would primarily delay the timing of cash flows, with a less significant impact on earnings given the annual reconciliation mechanism as described below. Use of average annual rate base and capital structure amounts (vs. year-end amounts), though, would unfavorably impact future earnings given increased regulatory lag.
ComEd is currently assessing the potential impacts of the proposed order and cannot predict the reduction in the revenue requirement the ICC may approve and which provisions of the ALJs’ proposed order will ultimately be included in the final order. As a proposed order, it has no independent legal effect as the ICC must vote on a final order which may materially vary from the findings and conclusions in the proposed order. If the ICC provides significant changes to ComEd’s filed revenue requirement request, it could have a material impact on ComEd’s future results of operations and cash flows.
As noted, the legislation provides for an annual reconciliation of the revenue requirement in effect in a given year to reflect the actual costs that the ICC determines are prudently and reasonably incurred for such year. The first year for which the reconciliation will be performed is 2011. ComEd made its initial 2011 reconciliation filing on April 30, 2012, and the rate adjustments necessary to reconcile the 2011 revenue requirement in effect to ComEd’s actual 2011 costs incurred will take effect in January 2013, after the ICC’s review. A similar 2012 annual reconciliation will be filed in early 2013 with any adjustments to rates taking effect in January 2014. As of March 31, 2012 and December 31, 2011, ComEd recorded an estimated regulatory asset of $118 million and $84 million, respectively, which represents ComEd’s best estimate of the probable increase in distribution rates expected to be approved by the ICC to provide for recovery of prudent and reasonable costs incurred as of those dates. Of the amount recorded at March 31, 2012, $61 million relates to 2011 and $57 million relates to the first quarter of 2012. During the first quarter of 2012, ComEd reduced the 2011 portion of the regulatory asset by $19 million to reflect management’s interpretation of how the ongoing formula rate tariff proceedings discussed above may impact the formula rate mechanism ultimately approved by the ICC. Based on its preliminary review, if the ALJ’s proposed order dated May 1, 2012, were to be implemented, ComEd does not believe it would have a material impact to the cumulative regulatory asset amount recorded as of March 31, 2012.
Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd). The ICC issued an order in ComEd’s 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEd on the treatment of post-test year accumulated depreciation and the recovery of system modernization costs via a rider (Rider SMP). On January 25, 2011, ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court that was denied on March 30, 2011. The ICC hassubsequently initiated a proceeding on remand. ComEd expects thatOn February 23, 2012, the ICC will issue a finalissued an order in that proceeding in early 2012.
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. An interest charge may accrue on any refund amount. 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. In August 2011, ComEd filed testimony in the remand proceeding that no refunds should be required. If the ICC decides refunds are required, ComEd’s testimony stated that the maximum potentialrequiring ComEd to provide a refund should be approximately $30 million. Intervenors and ICC Staff have filed testimony in the remand proceeding that ComEd should refundof approximately $37 million including interest, to customers related to the treatment of post-test year accumulated depreciation.
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. In 2009, the ICC approved a modified version of Rider SMP (Rider AMP). 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. Rider AMP is the subject of a separate appeal that is still pending. ComEd does not believe any of its other riders are affected by the Court’s ruling.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Subsequent to the Court’s ruling,depreciation issue. On March 26, 2012, ComEd filed a request with the ICC to allow it to request recovery, through inclusion in the 2010 Rate Case,notice of operation and maintenance costs that would have been recovered through Rider AMP, as well as continued rider recovery of carrying costs associated with capital investment in the ICC-approved AMI/Customer Applications pilot program until the conclusion of the 2010 rate case. The unrecovered Rider AMP 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.
appeal. ComEd has recognized for accounting purposes its best estimate of any refund obligation, subject to true-up when the ICC issues an order in the remand proceeding.
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 annual 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 was to allow ComEd to recover the costs of substantial investments made since its last rate filing in 2007. The requested increase also reflected increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The original requested rate of return on common equity was 11.5%. In addition, ComEd requested future recovery of certain amounts that were previously recorded as expense that would allow ComEd to recognize a one-time benefit of up to $40 million (pre-tax). The requested increase also included $22 million for increased uncollectible accounts expense, which would increase the threshold for determining over/under recoveries under ComEd’s uncollectible accounts tariff.
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 allowed 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 nine months ended September 30, 2011. The order also affirmed the current regulatory asset for severance costs which was challenged by an intervener in the 2010 Rate Case. The order has been appealed to the Court by several parties, including ComEd. ComEd cannot predict the 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 Illinois Public Utilities Act that contemplates an alternative regulatory structure. Rather than employing the traditional rate setting process in which the utility seeks recovery of costs already incurred, the proposal would have brought utilities, stakeholders, and the ICC 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.obligation.
Utility Consolidated Billing and Purchase of ReceivablesAdvanced Metering Program Proceeding (Exelon and ComEd)ComEd). In November 2008,October 2009, the ICC approved a modified version of ComEd’s system modernization rider proposed in the 2007 Rate Case, Rider AMP (Advanced Metering Program). ComEd collected approximately $24 million under Rider AMP through December 31, 2011. Several other parties, including the Illinois Public Utilities Act was amended to require ComEd to file tariffs establishing Utility Consolidated Billing and Purchase of Receivables services. On December 15,Attorney General, appealed the ICC’s order on Rider AMP. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s tariff offering PORCB (Purchasetransfer of Receivables with Consolidated Billing) services for RES. Beginning in the first quarter of 2011, ComEd is requiredother costs from recovery under Rider AMP to buy certain RES receivables, primarily residential and small commercial and industrial customers, at the option of the RES, for electric supply service and then include those amounts on ComEd’s bills to customers. Receivables are purchased at a discount to compensate ComEd for uncollectible
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
accounts. ComEd produces consolidated bills for the aforementioned retail customers reflecting charges for electric delivery service and purchased receivables. As of September 30, 2011, the balance of purchased accounts receivable associated with PORCB was $10 million. Under the tariff, ComEd recovers from RES and customers the costs for implementing and operating the program.
Legislation to Modernize Electric Utility Infrastructure and to Update Illinois Ratemaking Process (Exelon and ComEd). ComEd and Ameren 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 the 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 interveners the opportunity to review the prudence and reasonableness of costs. If the legislation were to be enacted, upon approval from ComEd’s Board of Directors, ComEd would anticipate filing annualbase electric distribution formula rate cases and investing an additional $2.6 billion (potentially up to $3 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.
rates. On September 12, 2011, the Governor vetoed the bill. The legislation will now go back to the General Assembly, which may elect to override the veto with a super-majority vote during the fourth quarter. If approved in its current form and upon approval of ComEd’s Board of Directors, 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 any 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.
Recovery of Uncollectible Accounts (Exelon and ComEd). On February 2, 2010, the ICC 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. As a result of that 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. 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 which is used to assist low-income residential customers. See Note 2 of the 2010 Form 10-K for additional information.
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 andMarch 19, 2012, the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Court reversed Rider AMP, concluding that the ICC’s October 2009 approval of the rider constituted single-issue ratemaking. ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court on April 23, 2012. ComEd believes any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Court’s order on March 19, 2012, which would have an immaterial impact at ComEd and Exelon.
Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from its retail customers without mark-up. Since June 2009, 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,EIMA contains a provision for the ICC approved the IPA’sIPA to conduct procurement plan covering the period June 2011 through May 2016. As of September 30, 2011, ComEd has completed the ICC-approved procurement processevents for its energy requirements through May 2012 as well as a portion of itsand REC requirements for each of the years ending in MayJune 2013 and May 2014.
through December 2017 period. 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 obligationevents mandated under the state’s RPS and all associated procurement costs will be recoverable from customers. As of September 30, 2011, ComEd hasEIMA were completed the ICC-approved procurement process for RECs through Mayduring February 2012. See Note 615 — Derivative Financial InstrumentsCommitments and Contingencies 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 inon 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 had been recording a reserve against a portion of these billings. The ICC order in the 2010 Rate Case clarified the method for determining CWC, and as a result, ComEd reversed a $17 million reserve during the second quarter of 2011.commitments.
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 revenues of $225 million and $20 million, respectively, which became effective on January 1, 2011. 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 tax benefits related to the application of any new IRS guidance on repairs deduction methodology are to be handled from a rate-making perspective. The settlements require that the expected cash benefit from the application of any new guidance to prior tax years be refunded to customers over a seven-year period. On August 19, 2011, the IRS issued Revenue Procedure 2011–43 providing a safe harbor method of tax accounting for electric transmission and distribution property. PECO adopted the safe harbor and elected a method change for the 2010 tax year. The expected total refund to customers for the tax cash benefit from the application of the safe harbor to costs incurred prior to 2010 is $171 million for which PECO has recorded a regulatory liability on Exelon’s and PECO’s Consolidated Balance Sheets as of September 30, 2011. On October 4, 2011, PECO filed a supplement to its electric distribution tariff to execute the refund to customers of the tax cash benefit related to the IRC Section 481(a) “catch-up” adjustment claimed on the 2010 income tax return, which is subject to adjustment based on the outcome of IRS examinations. Credits will be reflected in customer bills beginning January 1, 2012. Tax benefits claimed prospectively as a result of Revenue Procedure 2011–43 will be reflected as a reduction to income 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 distribution base rate cases. See Note 8 — Income Taxes for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Pennsylvania Procurement Proceedings (Exelon and PECO).PECO’s PAPUC-approved 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 commercialIn January 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,April 2012, PECO entered into contracts with PAPUC-approved bidders, including Generation, 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. In September 2011, PECO entered into contracts with PAPUC-approved bidders for its competitive procurement of electric supply for default electric service, which included block contracts for the residential procurement class commencing December 2011 and full requirements fixed price contracts for theits residential and small commercial, medium commercial procurement classes that commence in June 2012, hourly spot market price full requirements contracts for its small and medium commercial and large commercial and industrial procurement classes commencingthat commence in June 2012 and block contracts for its residential class beginning December 2012. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Statement of Operations. PECO will conduct three additionalhas one competitive procurementsprocurement remaining over the remainder of the term of itsthis DSP Program.
Electric PurchaseOn January 13, 2012, PECO filed its second DSP Plan for approval with the PAPUC. The plan outlined how PECO will purchase electricity for default customers from June 1, 2013 through May 31, 2015. To continue to ensure a competitive procurement process for residential customers, PECO proposed to procure electricity through a combination of Receivables Program. PECO’s revised electric POR program requires PECOone-year and two-year fixed full requirements contracts, reduce the amount of time between when the energy is purchased and when it is provided to purchase the customer accounts receivablecustomers and complete an annual, rather than quarterly, reconciliation 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 administrationactual versus forecasted energy use. The DSP Plan also proposed to eliminate the AEPS rider and recover AEPS costs through the GSA. Hearings on the filing are scheduled for May 2012, with a 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 September 30, 2011, the balance of receivables purchased under the revised POR program was $53 million. Receivables purchased under the previous POR program were $3 million as of December 31, 2010. The increaseruling expected 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.mid-October 2012.
Smart Meter and Smart Grid Investments (Exelon and PECO). In April 2010, the PAPUC approved PECO’s $550 million 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.by 2020. In 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA.ARRA of 2009. 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 nine months ended September 30, 2011, PECO received $52 million in reimbursements from the DOE. As of September 30, 2011, PECO’s outstanding receivable from the DOE for reimbursable costs was $16 million, which has been recorded in other accounts receivable, net on Exelon’s and PECO’s Consolidated Balance Sheets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
On April 15, 2011, the PAPUC issued the order approving the joint petition for partial settlement of the initial dynamic pricingits smart grid 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 universalsmart 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.infrastructure. 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 adjustments, which were approved by the PAPUC on August 18, 2011, 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$200 million SGIG 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 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 bebeing used to meet AEPS Act obligationsreduce the impact of these investments on PECO ratepayers.
As of March 31, 2012, PECO received $87 million in reimbursements from the 2011DOE. As of March 31, 2012, PECO’s outstanding receivable from the DOE for reimbursable costs was $28 million, which has been recorded in other accounts receivable, net on Exelon’s and 2012 compliance years.
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 by the PAPUC on February 10, 2011. 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 are being recovered on a full and current basis through a rider.PECO’s Consolidated Balance Sheets.
Natural Gas Choice Supplier Tariff (Exelon and PECO).On March 11, During 2011, PECO filedthe PAPUC approved PECO’s tariff supplements to its Gas Choice Supplier Coordination Tariff and theits Retail Gas Service Tariff to address the new licensing requirements for natural gas suppliers outlined(NGS) set forth in the PAPUC’s final rulemaking order, thatwhich became effective January 1, 2011. The new licensing requirements broaden the types of collateral that PECO can obtainrequire to mitigate its risk related to a natural gas choice supplierNGS default, andas well as PECO’s ability to adjust collateral when material changes in supplier creditworthiness exist.occur. PECO has completed its creditworthiness determinations and notified affected NGSs of their new collateral levels. As a result, PECO will obtain $14 million of assurance in May 2012.
Investigation of PennsylvaniaPA Retail Electricity Market (Exelon and PECO). On July 28, 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania’s retail electric market. The PAPUC found that the existing default service model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed theits Office of Competitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. On October 14,January 13, 2012, PECO filed its second Default Service Plan for approval with the PAPUC, which proposed several new programs to continue PECO’s support of retail market competition in Pennsylvania in accordance with the order issued by the PAPUC on December 15, 2011. On March 1, 2012, the PAPUC approved the final order describing more detailed recommendations to be implemented prior to the expiration of the electric distribution company’s current default service plan beginning in 2012 and providing guidelines for EDCs for the development of their next Default Service Plan.
Pennsylvania Act 11 of 2012 (Exelon and PECO). On February 13, 2012, Act 11 was signed into law by the Governor. Act 11 seeks to clarify the PAPUC’s authority to approve alternative ratemaking mechanisms, which would allow for the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania.
Act 11 also includes a provision that allows utilities to use a fully projected future test year under which the PAPUC may permit the inclusion of projected capital costs in rate base for assets that will be placed in service in future test years.
Maryland Regulatory Matters
2011 Maryland Electric and Natural Gas Distribution Rate Cases (Exelon and BGE). In March 2011, the PAPUCMDPSC issued for comment tentative recommendations to guidea comprehensive rate order setting forth the state’sdetails of the decision contained in its abbreviated electric and gas distribution companies in developing upcoming default service plans. A finalrate order is expected to be issued in December 2011. Final guidance on long-term structural changes is expected2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $19 million of costs as regulatory assets. These costs will be issuedrecovered over a 5-year period beginning December 2010 and include the deferral of $16 million of storm costs incurred in 2012.February 2010. The regulatory asset for the storm costs earns a regulated rate of return.
Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million residential and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
commercial electric and gas smart meters at an expected total cost of $480 million. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is delivered to customers. Under a grant from the DOE, BGE is a recipient of $200 million in federal funding for its smart grid and other related initiatives. This grant allows BGE to be reimbursed for smart grid and other expenditures up to $200 million, substantially reducing the total cost of these initiatives.
During the three months ended March 31, 2012, BGE received $14 million in reimbursements from the DOE. As of March 31, 2012, BGE’s outstanding receivable from the DOE for reimbursable costs was $1 million, which has been recorded in other accounts receivable, net on Exelon’s and BGE’s Consolidated Balance Sheets.
New Electric Generation (Exelon and BGE). On April 12, 2012, the MDPSC issued an order directing BGE and two other Maryland utilities to enter a contract for difference (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct a 661 MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, with a projected commercial operation date of June 1, 2015. The initial term of the proposed contract is 20 years. The CfD will provide that the utilities will pay (or receive) the difference between CPV’s contract prices and the revenues CPV receives for capacity and energy from bidding the unit into the PJM market. The utilities are required to enter into a CfD in amounts proportionate to their relative SOS load as of the date of execution. The utilities are directed to meet with CPV and the consultant for the MDPSC to negotiate changes to the CfD for submission to the MDPSC for approval. Depending on the precise terms of the CfD, the eventual market conditions and the manner of cost recovery, the CfD could have a material impact on Exelon’s and BGE’s financial results. On April 27, 2012, a civil complaint was filed in the United States District Court for the District of Maryland by certain unaffiliated parties that challenges the actions taken by the MDPSC on federal law grounds. Among other requests for relief, the plaintiffs seek to enjoin the MDPSC from executing or otherwise putting into effect any part of its order. On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order. Similar petitions have been filed by two other Maryland utilities in other Maryland State Courts.
Federal Regulatory Matters
Annual Transmission Formula Rate Update (Exelon and ComEd). ComEd’s most recent annual formula rate update filed in May 2011 reflects actual 2010 expenses and investments plus forecasted 2011 capital additions. The update resulted in a revenue requirement of $438 million offset by a $16 million reduction related to the true-up of 2010 actual costs for a net revenue requirement of $422 million. This compares to the May 2010 updated net revenue requirement of $416 million. The increase in the revenue requirement was primarily driven by the Illinois income tax statutory rate change enacted in January 2011. The 2011 net revenue requirement became effective June 1, 2011 and is recovered over the period extending through May 31, 2012. The regulatory liability associated with the true-up is being amortized as the associated amounts are refunded.
ComEd’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 9.10%, a decrease from the 9.27% return previously authorized. The decrease in return was primarily due to lower interest rates on ComEd’s long-term debt outstanding. 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 55%.
Market-Based Rates (Exelon, Generation, ComEd and PECO).Generation, ComEd and PECO are public utilities for purposes of the Federal Power Act and are required to obtain FERC’s acceptance of rate schedules for wholesale electricity sales. Currently, Generation, ComEd and 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 FERC Staff asked for a letter describing the amount of capacity affected by the PECO contract expiration and alternative transactions, which Generation filed on March 21, 2011. The impact 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 next updated market share screen analysis due to be filed 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 suppressingensure that a competitive capacity offer is based on the costs and competitive price signals for generation capacity.market revenues of a new entry unit. On February 1, 2011, in response to the enactment of New Jersey Senate Bill 2381, Exelon Generation joined a group of generating companies,the PJM Power Providers Group (P3), in filing complaint at FERC seeking a complaint asking FERCrevision to revise PJM’s MOPR to mitigate thispreclude the 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 PJM requested that FERC act on the proposed tariff amendment priorrevisions to the MayMOPR which were largely approved by FERC in its April 12, 2011 Order. The revised MOPR, among other things, sets a minimum price level for sell offers for capacity auction. Afrom certain types of new generation resources submitted in PJM’s capacity market auctions. While a number of state regulators and consumer groups have opposed the tariffMOPR revision, the changes but these changes arewere in line with recent FERC orders regarding capacity markets in the New York and New England ISOs. On April 12, 2011, FERC issued an order revising PJM’s MOPR to mitigate the exercise of buyer market power. Included in the FERC order was a revision to the MOPR whereby a subsidized plant cannot submit a bid into the auction for less than 90% of the cost of new entry of a plant of that type, unless the unit can justify a lower bid based on its costs. The minimum offer limitation continues until a unit clears the base residual RPM auction for the first time. After a unit clears once, it may bid in at any price, including zero. This may help reduce the magnitude of artificial suppression of capacity auction prices created by the actions of state regulators such as the capacity legislation in New Jersey. A
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
number of parties filed for rehearing of the FERC order on several different issues, including the question of whether the minimum price mitigation should apply to load serving entities that self-supply capacity. FERC scheduled the issue for consideration at a technical conference, while rehearing is pending.order.
License Renewals (Exelon and Generation) On August 18, 2009, PSEG submitted applications to the NRC 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 NRC is expected to spend a total of 22 to 30 months to review the applications before making a decision. The current operating licenses for Limerick Units 1 and 2 expire in 2024 and 2029, respectively.
Regulatory Assets and Liabilities (Exelon, ComEd, PECO and PECO)BGE)
Exelon, ComEd, PECO and PECOBGE 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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.
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of March 31, 2012 and December 31, 2011. The Registrants have reclassified certain regulatory asset and liability balances as of December 31, 2011 in order to align the reporting of regulatory activities subsequent to the closing of the merger with Constellation. For additional information on the specific regulatory assets and liabilities, refer to Note 2 of the Exelon 2011 Form 10-K for Exelon, ComEd and PECO and Note 6 of BGE’s 2011 Form 10-K.
March 31, 2012 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory assets | ||||||||||||||||||||||||||||||||
Pension and other postretirement benefits(a) | $ | 265 | $ | 3,512 | $ | — | $ | — | $ | 5 | $ | — | $ | 2 | $ | — | ||||||||||||||||
Deferred income taxes | 12 | 1,243 | 5 | 64 | — | 1,115 | 7 | 64 | ||||||||||||||||||||||||
AMI and smart meter programs | 2 | 46 | 2 | 6 | — | 22 | — | 18 | ||||||||||||||||||||||||
Under-recovered distribution service costs | 19 | 99 | 19 | 99 | — | — | — | — | ||||||||||||||||||||||||
Debt costs | 15 | 78 | 12 | 70 | 3 | 8 | 2 | 10 | ||||||||||||||||||||||||
Fair value of BGE long-term debt(b) | 41 | 253 | — | — | — | — | — | — | ||||||||||||||||||||||||
Fair value of BGE supply contract(c) | 117 | 89 | — | — | — | — | — | — | ||||||||||||||||||||||||
Severance | 28 | 44 | 25 | 31 | — | — | 3 | 13 | ||||||||||||||||||||||||
Asset retirement obligations | — | 76 | — | 52 | — | 24 | — | — | ||||||||||||||||||||||||
MGP remediation costs | 31 | 124 | 24 | 85 | 6 | 37 | 1 | 2 | ||||||||||||||||||||||||
RTO start-up costs | 3 | 3 | 3 | 3 | — | — | — | — | ||||||||||||||||||||||||
Under-recovered electric universal service fund costs | 5 | — | — | — | 5 | — | — | — | ||||||||||||||||||||||||
Financial swap with Generation | — | — | 590 | 92 | — | — | — | — | ||||||||||||||||||||||||
Renewable energy and associated RECs | 16 | 125 | 16 | 125 | — | — | — | — | ||||||||||||||||||||||||
Under-recovered energy and transmission costs | 139 | — | 85 | — | 9 | (d) | — | 45 | — | |||||||||||||||||||||||
DSP Program costs | 3 | 2 | — | — | 3 | 2 | — | — | ||||||||||||||||||||||||
Deferred storm costs | 3 | 8 | — | — | — | — | 3 | 8 | ||||||||||||||||||||||||
Electric generation-related regulatory asset | 16 | 52 | — | — | — | — | 16 | 52 | ||||||||||||||||||||||||
Rate stabilization deferral | 63 | 282 | — | — | — | — | 63 | 282 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 29 | 100 | — | — | — | — | 29 | 100 | ||||||||||||||||||||||||
Other | 39 | 32 | 12 | 17 | 17 | 9 | 3 | 4 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total regulatory assets | $ | 846 | 6,168 | $ | 793 | $ | 644 | $ | 48 | $ | 1,217 | $ | 174 | $ | 553 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
March 31, 2012 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory liabilities | ||||||||||||||||||||||||||||||||
Nuclear decommissioning | $ | — | $ | 2,430 | $ | — | $ | 2,017 | $ | — | $ | 413 | $ | — | $ | — | ||||||||||||||||
Removal costs | 86 | 1,396 | 64 | 1,191 | — | — | 22 | 205 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 42 | 79 | 42 | — | — | 79 | — | — | ||||||||||||||||||||||||
Electric distribution tax repairs | 20 | 145 | — | — | 20 | 145 | — | — | ||||||||||||||||||||||||
Over-recovered uncollectible accounts | 10 | — | 10 | — | — | — | — | — | ||||||||||||||||||||||||
Over-recovered energy and transmission costs | 55 | — | 11 | — | 44 | (e) | — | — | — | |||||||||||||||||||||||
Over-recovered gas universal service fund costs | 3 | — | — | — | 3 | — | — | — | ||||||||||||||||||||||||
Over-recovered AEPS costs | 6 | — | — | — | 6 | — | — | — | ||||||||||||||||||||||||
Customer rate credit | 113 | — | — | — | — | — | 113 | — | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total regulatory liabilities | $ | 335 | $ | 4,050 | $ | 127 | $ | 3,208 | $ | 73 | $ | 637 | $ | 135 | $ | 205 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory assets | ||||||||||||||||||||||||||||||||
Pension and other postretirement benefits | $ | 204 | $ | 2,794 | $ | — | $ | — | $ | 7 | $ | — | $ | 3 | $ | — | ||||||||||||||||
Deferred income taxes | 5 | 1,176 | 5 | 66 | — | 1,110 | 7 | 64 | ||||||||||||||||||||||||
AMI and smart meter programs | 2 | 28 | 2 | 6 | — | 22 | — | 15 | ||||||||||||||||||||||||
Under-recovered distribution service costs | 14 | 70 | 14 | 70 | — | — | — | — | ||||||||||||||||||||||||
Debt costs | 18 | 81 | 15 | 73 | 3 | 8 | 2 | 10 | ||||||||||||||||||||||||
Severance | 25 | 38 | 25 | 38 | — | — | — | 1 | ||||||||||||||||||||||||
Asset retirement obligations | — | 74 | — | 50 | — | 24 | — | — | ||||||||||||||||||||||||
MGP remediation costs | 30 | 129 | 24 | 91 | 6 | 38 | 1 | 2 | ||||||||||||||||||||||||
RTO start-up costs | 3 | 4 | 3 | 4 | — | — | — | — | ||||||||||||||||||||||||
Under-recovered electric universal service fund costs | 3 | — | — | — | 3 | — | — | — | ||||||||||||||||||||||||
Financial swap with Generation | — | — | 503 | 191 | — | — | — | — | ||||||||||||||||||||||||
Renewable energy and associated RECs | 9 | 97 | 9 | 97 | — | — | — | — | ||||||||||||||||||||||||
Under-recovered energy and transmission costs | 57 | — | 48 | — | 9 | (b) | — | 50 | — | |||||||||||||||||||||||
DSP Program costs | 3 | 2 | — | — | 3 | 2 | — | — | ||||||||||||||||||||||||
Deferred storm costs | — | — | — | — | — | — | 3 | 9 | ||||||||||||||||||||||||
Electric generation-related regulatory asset | — | — | — | — | — | — | 16 | 56 | ||||||||||||||||||||||||
Rate stabilization deferral | — | — | — | — | — | — | 63 | 295 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | — | — | — | — | — | — | 29 | 95 | ||||||||||||||||||||||||
Other | 17 | 25 | 9 | 13 | 8 | 12 | — | 3 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total regulatory assets | $ | 390 | $ | 4,518 | $ | 657 | $ | 699 | $ | 39 | $ | 1,216 | $ | 174 | $ | 550 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
December 31, 2011 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory liabilities | ||||||||||||||||||||||||||||||||
Nuclear decommissioning | $ | — | $ | 2,222 | $ | — | $ | 1,857 | $ | — | $ | 365 | $ | — | $ | — | ||||||||||||||||
Removal costs | 61 | 1,185 | 61 | 1,185 | — | — | 18 | 200 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 49 | 69 | 49 | — | — | 69 | — | — | ||||||||||||||||||||||||
Electric distribution tax repairs | 19 | 151 | — | — | 19 | 151 | — | — | ||||||||||||||||||||||||
Over-recovered uncollectible accounts | 15 | — | 15 | — | — | — | — | — | ||||||||||||||||||||||||
Over-recovered energy and transmission costs | 42 | — | 12 | — | 30 | (c) | — | — | — | |||||||||||||||||||||||
Over-recovered gas universal service fund costs | 3 | — | — | — | 3 | — | — | — | ||||||||||||||||||||||||
Over-recovered AEPS costs | 8 | — | — | — | 8 | — | — | — | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total regulatory liabilities | $ | 197 | $ | 3,627 | $ | 137 | $ | 3,042 | $ | 60 | $ | 585 | $ | 18 | $ | 200 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) | As of March 31, 2012, the pensions and other postretirement benefits line now includes a regulatory asset established at the date of the merger related to the recognition of BGE’s share of the underfunded status of the defined benefit postretirement plan as a liability on Exelon’s balance sheet. The regulatory asset is amortized in accordance with the authoritative guidance for pensions and postretirement benefits over a period of approximately 12 years. BGE is currently recovering these costs through base rates. BGE is not earning a return on the recovery of these costs in base rates. |
(b) | Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the Long-Term Debt of BGE as of the merger date. |
(c) | Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE’s supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. |
(d) | Relates to the under-recovered transmission costs. |
(e) | Includes $18 million and $5 million related to the over-recovered natural gas costs under the PGC and $26 million and $25 million related to the over-recovered electric supply costs under the GSA as of March 31, 2012 and December 31, 2011, respectively. |
Purchase of Receivables Programs (Exelon, ComEd, PECO, and BGE)
ComEd, PECO and BGE are required, under separate legislation and regulations in Illinois, Pennsylvania and Maryland, respectively, to purchase certain receivables from retail electric and natural gas suppliers. For retail suppliers participating in the utilities’ consolidated billing, ComEd, PECO and BGE must purchase their customer accounts receivables. ComEd and BGE purchase receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and permitted to recover uncollectible accounts expense from customers through distribution rates. Purchased receivables are classified in other accounts receivable, net on Exelon’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of March 31, 2012 and December 31, 2011.
As of March 31, 2012 | Exelon | ComEd | PECO | BGE | ||||||||||||
Purchased receivables(a) | $ | 146 | $ | 20 | $ | 57 | $ | 69 | ||||||||
Allowance for uncollectible accounts(b) | (13 | ) | (3 | ) | (6 | ) | (4 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Purchased receivables, net | $ | 133 | $ | 17 | $ | 51 | $ | 65 | ||||||||
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
As of December 31, 2011 | Exelon(c) | ComEd | PECO | BGE | ||||||||||||
Purchased receivables(a) | $ | 68 | $ | 16 | $ | 52 | $ | 61 | ||||||||
Allowance for uncollectible accounts(b) | (5 | ) | — | (5 | ) | (3 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Purchased receivables, net | $ | 63 | $ | 16 | $ | 47 | $ | 58 | ||||||||
|
|
|
|
|
|
|
|
(a) | PECO’s gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers. |
(b) | For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff. |
5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)
As a result of the Constellation merger, Generation now owns a 50.01% interest in CENG, a nuclear generation business. Generation’s total equity in losses of the investment in CENG is as follows:
For the Period March 12 through March 31, 2012 | ||||
CENG | $ | (9 | ) | |
Amortization of basis difference in CENG | (12 | ) | ||
|
| |||
Total equity investment losses — CENG | $ | (21 | ) | |
|
|
Generation has an initial basis difference of approximately $183 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference is created by the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation will amortize this basis difference over the respective useful lives of the assets of CENG or as those assets and liabilities impact the earnings of CENG.
In future periods, Generation may be eligible for distributions from CENG in excess of its 50.01% ownership interest based on tax sharing provisions contained in the operating agreement for CENG. Generation would record these distributions, if realized, in earnings in the period earned.
Related Party Transactions (Exelon and Generation)
CENG
Generation has an agreement with CENG under which it will purchase between 85-90% of the output of CENG’s nuclear plants that is not sold to third parties under pre-existing firm and unit contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit contingent basis 50.01% of the output of CENG’s nuclear plants, and EDF will purchase on a unit contingent basis 49.99% of the output.
In addition to the PPA, a subsidiary of Generation has a power services agency agreement (PSAA) with CENG. The PSAA is a five-year agreement under which Generation provides scheduling, asset management and billing services to CENG for a specified monthly fee. On January 16, 2012, Exelon agreed to amend the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
PSAA, effective as of the closing of the merger with Constellation, to adjust the charges for services to reflect the cost of the service, with such cost not to exceed approximately $358,000 per month.
In addition to the PSAA, Exelon has an administrative services agreement (ASA) with CENG, which expires in 2017. Under the ASA, Exelon BSC provides certain administrative services to CENG including back office, human resources and information technology. The ASA includes both a consumption-based pricing structure and a fixed-price structure which are subject to change in future years based on the level of service needed. On January 16, 2012, Exelon agreed to amend the ASA, effective as of the close of the merger with Constellation, to adjust the charges for services to reflect actual post-merger costs determined on the same basis that Exelon BSC charges its affiliates for similar services.
The impact of transactions under these agreements on Exelon’s and Generation’s financial statements is summarized below:
Increase/(Decrease) in Earnings | Income Statement Classification | Accounts Receivable/ (Accounts Payable) At March 31, 2012 | ||||||||
Agreement | March 12, 2012 through March 31, 2012 | |||||||||
PPA | $ | (35 | ) | Purchased power and fuel | $ | (60 | ) | |||
PSA | 1 | Operating revenues | — | |||||||
ASA | 3 | Operating expenses | 3 |
In May 2011, CENG issued an unsecured revolving promissory note to borrow up to an aggregate principal amount of $62.5 million from a subsidiary of Generation. CENG also issued a promissory note to EDF on substantially identical terms, such that any request for borrowings by CENG must be submitted 50% to Generation and 50% to EDF.
Interest accrues on the amounts borrowed on a daily basis at a rate of LIBOR, plus an adder of 250 basis points. Amounts are due at the earlier of October 31, 2012 or the date upon which the note is accelerated in accordance with the terms of the agreement.
As of March 31, 2012, CENG had borrowed $42.5 million from Generation.
6. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)
Fair Value of Financial Liabilities Recorded at the Carrying Amount
The following tables provide information aboutpresent the regulatory assetscarrying amounts and fair values of the Registrants’ short-term liabilities, of Exelon, ComEdlong-term debt, SNF obligation and PECOpreferred securities as of September 30, 2011March 31, 2012 and December 31, 2010. For additional information on the specific regulatory assets and liabilities, refer to Note 2 of the 2010 Form 10-K.2011:
Exelon
September 30, 2011 | Exelon | ComEd | PECO | |||||||||
Regulatory assets | ||||||||||||
Pension and other postretirement benefits | $ | 2,671 | $ | — | $ | 8 | ||||||
Deferred income taxes | 1,161 | 70 | (a) | 1,091 | ||||||||
AMI and smart meter program expenses | 31 | 9 | 22 | |||||||||
Debt costs | 105 | 93 | 12 | |||||||||
Severance(b) | 69 | 69 | — | |||||||||
Asset retirement obligations | 74 | 50 | 24 | |||||||||
MGP remediation costs | 161 | 115 | 46 | |||||||||
RTO start-up costs | 8 | 8 | — | |||||||||
Financial swap with Generation — noncurrent | — | 247 | — | |||||||||
Renewable energy and associated RECs — noncurrent(c) | 48 | 48 | — | |||||||||
DSP Program costs | 6 | — | 6 | |||||||||
Other | 47 | 24 | 24 | |||||||||
|
|
|
|
|
| |||||||
Noncurrent regulatory assets | 4,381 | 733 | 1,233 | |||||||||
Financial swap with Generation — current | — | 415 | — | |||||||||
Under-recovered energy and transmission costs | 28 | 24 | 4 | (d) | ||||||||
DSP Program electric procurement contracts(e) | 1 | — | 3 | |||||||||
Renewable energy and associated RECs — current(c) | 2 | 2 | — | |||||||||
|
|
|
|
|
| |||||||
Current regulatory assets | 31 | 441 | 7 | |||||||||
|
|
|
|
|
| |||||||
Total regulatory assets | $ | 4,412 | $ | 1,174 | $ | 1,240 | ||||||
|
|
|
|
|
| |||||||
Regulatory liabilities | ||||||||||||
Nuclear decommissioning(f) | $ | 2,077 | $ | 1,748 | $ | 329 | ||||||
Removal costs | 1,239 | 1,239 | — | |||||||||
Refund of PURTA taxes | 1 | — | 1 | |||||||||
Energy efficiency and demand response programs | 108 | 46 | 62 | |||||||||
Over-recovered uncollectible accounts | 5 | 5 | — | |||||||||
Electric transmission and distribution tax repairs | 171 | — | 171 | |||||||||
|
|
|
|
|
| |||||||
Noncurrent regulatory liabilities | 3,601 | 3,038 | 563 | |||||||||
Over-recovered energy and transmission costs | 50 | 17 | 33 | (g) | ||||||||
Over-recovered universal service fund costs(h) | 3 | — | 3 | |||||||||
Over-recovered AEPS costs | 7 | — | 7 | |||||||||
|
|
|
|
|
| |||||||
Current regulatory liabilities | 60 | 17 | 43 | |||||||||
|
|
|
|
|
| |||||||
Total regulatory liabilities | $ | 3,661 | $ | 3,055 | $ | 606 | ||||||
|
|
|
|
|
|
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 | |||||||||
AMI and 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 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2012 | December 31, 2011 | |||||||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
Short-term liabilities | $ | 1,036 | $ | 472 | $ | 564 | $ | — | $ | 737 | $ | 737 | ||||||||||||
Long-term debt (including amounts due within one year) | 17,545 | — | 18,918 | 162 | 12,627 | 14,488 | ||||||||||||||||||
Long-term debt to financing trusts | 648 | — | 641 | — | 390 | 358 | ||||||||||||||||||
SNF obligation | 1,019 | — | 882 | — | 1,019 | 886 | ||||||||||||||||||
Preferred securities of subsidiary | 87 | — | 79 | — | 87 | 79 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Operating and Maintenance for Regulatory Required Programs (Exelon, ComEd and PECO)Generation
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 approved regulated rates for ComEd and PECO for the three and nine months ended September 30, 2011 and 2010. An equal and offsetting amount has been reflected in operating revenues during the periods.
For the Three Months Ended September 30, 2011 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 52 | $ | 41 | $ | 11 | ||||||
Smart meter program | 3 | — | 3 | |||||||||
Purchased power administrative costs | 3 | 2 | 1 | |||||||||
Consumer education program | 1 | — | 1 | |||||||||
|
|
|
|
|
| |||||||
Total operating and maintenance for regulatory required programs | $ | 59 | $ | 43 | $ | 16 | ||||||
|
|
|
|
|
| |||||||
For the Nine Months Ended September 30, 2011 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 122 | $ | 80 | $ | 42 | ||||||
Smart meter program | 7 | — | 7 | |||||||||
Purchased power administrative costs | 7 | 4 | 3 | |||||||||
Consumer education program | 2 | — | 2 | |||||||||
|
|
|
|
|
| |||||||
Total operating and maintenance for regulatory required programs | $ | 138 | $ | 84 | $ | 54 | ||||||
|
|
|
|
|
| |||||||
For the Three Months Ended September 30, 2010 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 35 | $ | 21 | $ | 14 | ||||||
Purchased power administrative costs | 1 | 1 | — | |||||||||
Consumer education program | 1 | — | 1 | |||||||||
|
|
|
|
|
| |||||||
Total operating and maintenance for regulatory required programs | $ | 37 | $ | 22 | $ | 15 | ||||||
|
|
|
|
|
| |||||||
For the Nine Months Ended September 30, 2010 | Exelon | ComEd | PECO | |||||||||
Energy efficiency and demand response programs | $ | 93 | $ | 59 | $ | 34 | ||||||
Purchased power administrative costs | 3 | 3 | — | |||||||||
Consumer education program | 2 | — | 2 | |||||||||
|
|
|
|
|
| |||||||
Total operating and maintenance for regulatory required programs | $ | 98 | $ | 62 | $ | 36 | ||||||
|
|
|
|
|
|
March 31, 2012 | December 31, 2011 | |||||||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
Short-term liabilities | $ | 114 | $ | — | $ | 114 | $ | — | $ | 2 | $ | 2 | ||||||||||||
Long-term debt (including amounts due within one year) | 6,646 | — | 6,804 | 67 | 3,677 | 4,231 | ||||||||||||||||||
SNF obligation | 1,019 | — | 882 | — | 1,019 | 886 |
4. Merger and Acquisitions (Exelon and Generation)ComEd
March 31, 2012 | December 31, 2011 | |||||||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
Short-term liabilities | $ | 302 | $ | — | $ | 302 | $ | — | $ | — | $ | — | ||||||||||||
Long-term debt (including amounts due within one year) | 5,215 | — | 6,067 | 18 | 5,665 | 6,540 | ||||||||||||||||||
Long-term debt to financing trust | 206 | — | 206 | — | 206 | 184 |
Proposed Merger with Constellation Energy Group, Inc. (Exelon)PECO
On April 28, 2011, Exelon
March 31, 2012 | December 31, 2011 | |||||||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
Short-term liabilities | $ | 225 | $ | — | $ | 225 | $ | — | $ | 225 | $ | 225 | ||||||||||||
Long-term debt (including amounts due within one year) | 1,972 | — | 2,291 | — | 1,972 | 2,295 | ||||||||||||||||||
Long-term debt to financing trusts | 184 | — | 176 | — | 184 | 174 | ||||||||||||||||||
Preferred securities | 87 | — | 79 | — | 87 | 79 |
BGE
March 31, 2012 | December 31, 2011 | |||||||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,101 | $ | — | $ | 2,359 | $ | — | $ | 2,101 | $ | 2,377 | ||||||||||||
Long-term debt to financing trusts | 258 | — | 259 | — | 258 | 256 |
Short-Term Liabilities. The short-term liabilities included in the table above are comprised of short-term borrowings (Level 2), short-term notes payable related to PECO’s accounts receivable agreement (Level 2), 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.dividends payable (Level 1). 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. CompletionRegistrants’ carrying amounts of the transaction is also conditioned upon approval byshort-term liabilities are representative of fair value because of the FERC, NRC, Maryland Public Service Commission (MDPSC), the New York Public Service Commission, the Public Utility Commissionshort-term nature of Texas (PUCT),these instruments. See Note 8 — Debt and Credit Agreements for additional information on PECO’s accounts receivable agreement.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
other state and federal regulatory bodies. The companies 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 October 2011, Exelon and Constellation reached a settlement with the PJM Independent Market Monitor, who had previously raised market power concerns regarding the merger. The settlement contains a number of commitments by the merged company, including limiting the universe of potential buyers of the divested assets to entities without significant market shares in the relevant PJM markets. The settlement also includes assurances about how the merged company will bid its units into the PJM markets. 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 FTC and/or the Antitrust Division of the 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 PUCT seeking approval of the transaction. Exelon and Constellation also filed an application with the NRC for indirect transfer of Constellation’s nuclear operating licenses and filed notifications with the FTC and DOJ in compliance with the requirements of the HSR Act. During the third quarter, Exelon and Constellation received approval of the transaction from the PUCT.
Exelon was 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. Similar suits were also filed in the United States District Court for the District of Maryland. The suits sought to enjoin a Constellation shareholder vote on the proposed merger until all material information is disclosed and sought rescission of the proposed merger. During the third quarter, the parties to the suits reached an agreement in principle to settle the suits through additional disclosures to Constellation shareholders. The settlement is subject to court approval.
Through September 30, 2011, Exelon has incurred approximately $37 million of expense associated with the transaction, primarily related to fees incurred as part of the acquisition. 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 or 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.
Acquisition of Antelope Valley Solar Ranch One (Exelon and Generation)
On September 30, 2011, Exelon announced the completion of its acquisition of all of the interest in Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar photovoltaic (PV) project under development in northern Los Angeles County, California, from First Solar, Inc., which developed and will build, operate, and maintain the project. Construction has started, with the first portion of the project expected to come online in late 2012 and full operation planned for late 2013. The acquisition builds on the Exelon commitment to clean energy as part of Exelon 2020, a business and environmental strategy to eliminate the equivalent of Exelon’s 2001 carbon footprint. The project has a 25-year PPA, approved by the California Public Utilities Commission, with Pacific Gas & Electric Company for the full output of the plant.
Exelon expects to invest up to $713 million in equity in the project through 2013. The DOE’s Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Bank to support the financing of the construction of the project. The purchase agreement contains a provision that First Solar, Inc. will repurchase Antelope Valley if initial funding of the loan does not occur by the end of 2011. See Note 7 — Debt and Credit Agreements for additional information on the loan guaranteed by the DOE.
Consistent with the applicable accounting guidance, the fair value of Antelope Valley’s assets and liabilities were determined as of the acquisition date.Long-Term Debt. The fair value of assets acquired and liabilities assumed was determined through 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 the amount and timing); discount rates reflecting the risk inherent in the future cash flows; and future market prices based on the Market Price Referent (MPR) established by the California PUC for renewable energy resources. Generation did not record any goodwill related to the acquisition of Antelope Valley.
The following table summarizes the fair value of consideration transferred to acquire Antelope Valley and the fair value of identified assets and liabilities assumed as of the acquisition date:
Fair Value of Consideration Transferred
Cash | $ | 75 | ||
|
| |||
Total fair value of consideration transferred | $ | 75 | ||
|
| |||
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed | ||||
Intangible asset | $ | 190 | ||
Property, plant and equipment | 15 | |||
Payable to First Solar, Inc. | (135 | ) | ||
Other Assets | 5 | |||
|
| |||
Total net identifiable assets | $ | 75 | ||
|
|
Accounting guidance requires that the acquirer must recognize separately identifiable intangible assets in the application of purchase accounting. Upon completion of the development project, all of the output will be sold under the PPA with Pacific Gas & Electric. The excess of the contract price of the PPA over forecasted MPR-based market prices was recognized as an intangible asset. Generation determined that the acquisition-date fair value of the intangible asset was approximately $190 million, which was recorded in other deferred debits and other assets within Exelon and Generation’s Consolidated Balance Sheets. While Generation expects to perform under the PPA once the construction of this project is complete, there is a risk of impairment if the project does not reach commercial operation. The valuation of the acquired intangible asset was estimated by applying the income approach, which is based upon discounted projected future cash flows associated with the PPA. That measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include forecasted MRP-based market prices and discount rate. The intangible asset will be amortized as revenue is earned over the term of the underlying PPA. The amortization expense will be reflected as a decrease in operating revenue within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. Exelon concluded that the remaining, yet-to-be paid $135 million in consideration was embedded in the amounts payable under the Engineering, Procurement, Construction (EPC) agreement for First Solar, Inc. to construct the solar facility. For accounting purposes, this aspect of the transaction is considered to be akin to a “seller financing” arrangement. As such, Exelon recorded a liability of $135 million associated with the portion of the future payments to First Solar, Inc. under the EPC agreement to reflect Generation’s implicit amounts due First Solar, Inc. for the remainder of the value of the net assets acquired. The $135 million payable to First Solar, Inc. will be relieved as Generation makes payments for costs incurred over the project construction period.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
In 2011, Exelon and Generation incurred approximately $8 million of acquisition-related costs associated with this transaction. These costs are included within operating and maintenance expense in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Acquisition of Wolf Hollow, LLC (Exelon and Generation)
On August 24, 2011, Generation completed the acquisition of all of the equity interests of Wolf Hollow, LLC (Wolf Hollow), a combined-cycle, natural gas-fired power plant in north Texas, pursuant to which Generation added 720 MWs of capacity within the ERCOT power market, which will further reduce Exelon’s carbon footprint. The acquisition builds on the Exelon commitment to clean energy as part of Exelon 2020. In connection with the acquisition, Generation terminated and settled its existing long-term PPA with Wolf Hollow, resulting in a gain of approximately $6 million, which is included within operating revenues (other revenue) in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
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 the timing and amounts of plant operating costs), discount rates reflecting the risk inherent in the future cash flows and future power and fuel 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. The PPA gain was calculated based on projected PPA cash flows relative to market power prices and the underlying terms of the agreement. Generation recognized an approximately $36 million non-cash bargain purchase gain (i.e., negative goodwill). The gain was included within other, net in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. Working capital is subject to a 180-day adjustment period.
The following table summarizes the fair value of consideration transferred to acquire Wolf Hollow and the value of identified assets and liabilities assumed as of the acquisition date:
Fair Value of Consideration Transferred
Total fair value of consideration transferred | $ | 311 | ||
Less: Gain on PPA settlement | 6 | |||
|
| |||
Cash | $ | 305 | ||
|
| |||
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed | ||||
Property, plant and equipment | $ | 347 | ||
Inventory | 5 | |||
Working capital, net | (5 | ) | ||
|
| |||
Total net identifiable assets | $ | 347 | ||
|
| |||
Bargain purchase gain | $ | 36 | ||
|
|
Consistent with the applicable accounting guidance, the fair value of Wolf Hollow’s assets and liabilities wasExelon’s taxable debt securities are determined as of the August 24, 2011 acquisition date. Increases in observable forward market power prices since the May 2011 transaction announcement date, primarily reflecting the impact on the Texas power markets of the Cross-State Air Pollution Rule (CSAPR) final regulations issued by the EPA in July 2011, as well as sustained hot weather in Texas, resulted in an increase in fair value of the net assets as of the acquisition date, resulting in the bargain purchase gain.
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 receivables for insurance claims of $14 million shown in working capital above. This amount represents insured repair costs incurred prior to the acquisition date, less the applicable deductible. As of September 30, 2011, approximately $14 million remains outstanding, which Generation expects to collect by the end of 2011.
Wolf Hollow’s revenue and operating income contribution to Exelon and Generation for the period from August 25, 2011 to September 30, 2011 was approximately $16 million and $4 million, respectively. The unaudited pro forma results for Exelon and Generation as if the Wolf Hollow acquisition occurred on January 1, 2010 were not materially different from Exelon and Generation’s financial results for the three and nine months ended September 30, 2011 and 2010. Exelon and Generation incurred approximately $4 million of acquisition-related costs associated with this transaction. These costs are included within operating and maintenance expense in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
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.
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 transferred | $ | 925 | ||
|
| |||
Recognized amounts of identifiable assets acquired and liabilities assumed | ||||
Property, plant and equipment | $ | 700 | ||
Intangible assets | 224 | |||
Working capital, net | 18 | |||
Asset retirement obligations | (13 | ) | ||
Noncontrolling interest | (3 | ) | ||
Other | (1 | ) | ||
|
| |||
Total net identifiable assets | $ | 925 | ||
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The contingent consideration arrangement requires that Generation pay up to $40 million related to three individual projects with an aggregate capacity of 230 MWs, which are currently in advanced stages of development or under construction, 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 as of the acquisition date 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. During the third quarter of 2011, $16 million of contingent consideration was paid to Deere & Company for one of the projects and the probability of a second project beginning construction was increased to 100%. As a result, $2 million expense was recorded in operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income and the contingent consideration included within other current liabilities within Exelon and Generation’s Consolidated Balance Sheets was adjusted to $10 million to reflect the full expected contingent payment related to the Harvest II project. The remaining $8 million of contingent consideration is included in other deferred credits and other liabilities within Exelon and Generation’s Consolidated Balance Sheets.
The fair value of the assets acquired included customer receivables of $18 million. 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 prepared 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 nine months ended September 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 nine months ended September 30, 2011 was $3 million and $9 million, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 September 30, 2011:
Estimated amortization expense | ||||||||||||||||||||||||||||||||
Gross | Accumulated Amortization | Net | Remainder of 2011 | 2012 | 2013 | 2014 | 2015 | |||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||||||||
Exelon Wind | $ | 224 | $ | (10 | ) | $ | 214 | $ | 3 | $ | 13 | $ | 14 | $ | 14 | $ | 14 | |||||||||||||||
Antelope Valley | 190 | — | 190 | — | 18 | 39 | 24 | 17 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total intangible assets | $ | 414 | $ | (10 | ) | $ | 404 | $ | 3 | $ | 31 | $ | 53 | $ | 38 | $ | 31 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd and PECO)
Non-Derivative Financial Assets and Liabilities. As of September 30, 2011 and December 31, 2010, the Registrants’ carrying amounts of cash and certain cash equivalents, accounts receivable, accounts payable, short term notes payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments.
Fair Value of Financial Liabilities Recorded at the Carrying Amount
Exelon
The carrying amounts and fair values of Exelon’s long-term debt, SNF obligation and preferred securities as of September 30, 2011 and December 31, 2010 were as follows:
September 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 13,414 | $ | 14,889 | $ | 12,213 | $ | 12,960 | ||||||||
Long-term debt to financing trusts | 390 | 355 | 390 | 350 | ||||||||||||
SNF obligation | 1,019 | 846 | 1,018 | 876 | ||||||||||||
Preferred securities of subsidiary | 87 | 75 | 87 | 68 |
The fair value of long-term debt is determined using a valuation model whichthat is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
The Registrants also have tax-exempt debt. Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value of preferred securities of subsidiaries is determined using observable market prices as these securities are actively traded.described above.
SNF Obligation. The carrying amount of Exelon and Generation’s SNF obligation resultedis derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. Exelon and Generation’s obligation to the DOE accrues at the 13-week Treasury rate. When determining the fair value of the obligation, the future carrying amount of the SNF obligation in 2020 is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The future compounded obligation amount is discounted back to present using Generation’s discount rate, which is calculated using the prevailing Treasury ratesame methodology as described above for a long-term obligation withthe taxable debt securities, and an estimated maturity date of 2020 (after being adjusted for Generation’s credit risk).
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)2020.
(Dollars in millions, except per share data, unless otherwise noted)Preferred Securities of Subsidiary, Long-term Debt to Financing Trusts and Junior Subordinated Debentures. The fair value of these securities is determined using observable market prices on the last trade date of the quarter as these securities are actively traded, less accrued interest. The securities are registered with the SEC and are public.
Generation
The carrying amounts and fair values of Generation’s long-term debt and spent nuclear fuel obligations as of September 30, 2011 and December 31, 2010 were as follows:
September 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 3,677 | $ | 4,053 | $ | 3,679 | $ | 3,792 | ||||||||
SNF obligation | 1,019 | 846 | 1,018 | 876 |
ComEd
The carrying amounts and fair values of ComEd’s long-term debt as of September 30, 2011 and December 31, 2010 were as follows:
September 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 6,202 | $ | 6,920 | $ | 5,001 | $ | 5,411 | ||||||||
Long-term debt to financing trust | 206 | 183 | 206 | 176 |
PECO
The carrying amounts and fair values of PECO’s long-term debt and preferred securities as of September 30, 2011 and December 31, 2010 were as follows:
September 30, 2011 | December 31, 2010 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,222 | $ | 2,483 | $ | 2,222 | $ | 2,402 | ||||||||
Long-term debt to financing trusts | 184 | 172 | 184 | 173 | ||||||||||||
Preferred securities | 87 | 75 | 87 | 68 |
Recurring Fair Value Measurements
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy 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, certain 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 and mutual 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.derivatives and investments priced using an alternative pricing mechanism.
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2012.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
There were no significant transfers between Level 1 and Level 2 during the nine months ended September 30, 2011.
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 September 30, 2011March 31, 2012 and December 31, 2010:2011:
As of September 30, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 1,485 | $ | — | $ | — | $ | 1,485 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 320 | 20 | — | 340 | ||||||||||||
Equity securities(b) | 1,147 | — | — | 1,147 | ||||||||||||
Commingled funds(c) | — | 1,791 | — | 1,791 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 598 | 91 | — | 689 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 549 | — | 549 | ||||||||||||
Corporate debt securities | — | 701 | — | 701 | ||||||||||||
Federal agency mortgage-backed securities | — | 901 | — | 901 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 116 | — | 116 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 5 | — | 5 | ||||||||||||
Other debt obligations | — | 64 | 6 | 70 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 2,065 | 4,238 | 6 | 6,309 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||
Equity securities | 43 | — | — | 43 | ||||||||||||
Commingled funds(c) | — | 67 | — | 67 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 114 | 22 | — | 136 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 49 | — | 49 | ||||||||||||
Corporate debt securities | — | 291 | — | 291 | ||||||||||||
Federal agency mortgage-backed securities | — | 123 | — | 123 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 12 | — | 12 | ||||||||||||
Private equity | — | — | 38 | 38 | ||||||||||||
Other debt obligations | — | 2 | — | 2 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning subtotal(e) | 157 | 566 | 38 | 761 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Rabbi trust investments | ||||||||||||||||
Mutual funds(f) | 34 | — | — | 34 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Rabbi trust investments subtotal | 34 | — | — | 34 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 413 | — | 413 | ||||||||||||
Other derivatives | — | 1,209 | 15 | 1,224 | ||||||||||||
Proprietary trading | — | 165 | 52 | 217 | ||||||||||||
Effect of netting and allocation of collateral(g) | (1 | ) | (1,058 | ) | (17 | ) | (1,076 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Mark-to-market assets(h) | (1 | ) | 729 | 50 | 778 | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total assets | 3,740 | 5,533 | 94 | 9,367 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Liabilities | ||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges(i) | — | (141 | ) | — | (141 | ) | ||||||||||
Other derivatives | (1 | ) | (651 | ) | (67 | ) | (719 | ) | ||||||||
Proprietary trading | — | (161 | ) | (26 | ) | (187 | ) | |||||||||
Effect of netting and allocation of collateral(g) | 1 | 910 | 18 | 929 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Mark-to-market liabilities(h) | — | (43 | ) | (75 | ) | (118 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Deferred compensation | — | (69 | ) | — | (69 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total liabilities | — | (112 | ) | (75 | ) | (187 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Total net assets | $ | 3,740 | $ | 5,421 | $ | 19 | $ | 9,180 | ||||||||
|
|
|
|
|
|
|
|
As of March 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 187 | $ | — | $ | — | $ | 187 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 428 | — | — | 428 | ||||||||||||
Equity | ||||||||||||||||
Equity securities | 1,460 | — | — | 1,460 | ||||||||||||
Commingled funds | — | 2,027 | — | 2,027 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Equity funds subtotal | 1,460 | 2,027 | — | 3,487 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income | ||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 941 | 1 | — | 942 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 328 | — | 328 | ||||||||||||
Debt securities issued by foreign governments | — | 67 | — | 67 | ||||||||||||
Corporate debt securities | — | 1,534 | — | 1,534 | ||||||||||||
Federal agency mortgage-backed securities | — | 55 | — | 55 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 39 | — | 39 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 8 | — | 8 | ||||||||||||
Mutual funds | — | 2 | — | 2 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income subtotal | 941 | 2,034 | — | 2,975 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Direct lending securities | — | — | 13 | 13 | ||||||||||||
Other debt obligations | — | 11 | — | 11 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,829 | 4,072 | 13 | 6,914 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||
Equity | ||||||||||||||||
Equity securities | 26 | — | — | 26 | ||||||||||||
Commingled funds | — | 22 | — | 22 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Equity funds subtotal | 26 | 22 | — | 48 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income | ||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 63 | 24 | — | 87 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 53 | — | 53 | ||||||||||||
Corporate debt securities | — | 325 | — | 325 | ||||||||||||
Federal agency mortgage-backed securities | — | 100 | — | 100 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 10 | — | 10 | ||||||||||||
Commingled funds | — | 40 | — | 40 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income subtotal | 63 | 552 | — | 615 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Direct lending securities | — | — | 42 | 42 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 89 | 574 | 42 | 705 | ||||||||||||
|
|
|
|
|
|
|
|
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) | $ | 1,473 | $ | — | $ | — | $ | 1,473 | ||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||
As of March 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||
Cash equivalents | 1 | — | — | 1 | 2 | — | — | 2 | ||||||||||||||||||||||||
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 | 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 | ||||||||||||||||||||||||||||
Mutual funds(d)(e) | 73 | — | — | 73 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Rabbi trust investments subtotal | 36 | — | — | 36 | 75 | — | — | 75 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Mark-to-market derivative assets | ||||||||||||||||||||||||||||||||
Cash flow hedges | — | 724 | 12 | 736 | ||||||||||||||||||||||||||||
Other derivatives | 2 | 1,709 | 57 | 1,768 | ||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||
Economic hedges | 1,988 | 6,913 | 990 | 9,891 | ||||||||||||||||||||||||||||
Proprietary trading | — | 235 | 46 | 281 | 3,341 | 6,427 | 219 | 9,987 | ||||||||||||||||||||||||
Effect of netting and allocation of collateral(g) | (3 | ) | (1,848 | ) | (38 | ) | (1,889 | ) | ||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | (5,329 | ) | (11,418 | ) | (370 | ) | (17,117 | ) | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Mark-to-market assets(h) | (1 | ) | 820 | 77 | 896 | |||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal(g) | — | 1,922 | 839 | 2,761 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets | — | 119 | — | 119 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Other investments | 3 | — | 14 | 17 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total assets | 3,776 | 5,748 | 77 | 9,601 | 3,183 | 6,687 | 908 | 10,778 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||
Cash flow hedges | — | (45 | ) | — | (45 | ) | ||||||||||||||||||||||||||
Other derivatives | (2 | ) | (667 | ) | (29 | ) | (698 | ) | ||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||
Economic hedges | (2,527 | ) | (5,659 | ) | (449 | ) | (8,635 | ) | ||||||||||||||||||||||||
Proprietary trading | — | (233 | ) | (21 | ) | (254 | ) | (3,457 | ) | (6,146 | ) | (364 | ) | (9,967 | ) | |||||||||||||||||
Effect of netting and allocation of collateral(g) | 1 | 914 | 23 | 938 | ||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | 5,755 | 10,791 | 333 | 16,879 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Mark-to-market liabilities(h) | (1 | ) | (31 | ) | (27 | ) | (59 | ) | ||||||||||||||||||||||||
Commodity mark-to-market liabilities subtotal(h) | (229 | ) | (1,014 | ) | (480 | ) | (1,723 | ) | ||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities | — | (54 | ) | — | (54 | ) | ||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Deferred compensation | — | (76 | ) | — | (76 | ) | — | (106 | ) | — | (106 | ) | ||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total liabilities | (1 | ) | (107 | ) | (27 | ) | (135 | ) | (229 | ) | (1,174 | ) | (480 | ) | (1,883 | ) | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total net assets | $ | 3,775 | $ | 5,641 | $ | 50 | $ | 9,466 | $ | 2,954 | $ | 5,513 | $ | 428 | $ | 8,895 | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
As of December 31, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 861 | $ | — | $ | — | $ | 861 | ||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||
Cash equivalents | 562 | — | — | 562 | ||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||
Equity securities | 1,275 | — | — | 1,275 | ||||||||||||||||||||||||||||
Commingled funds | — | 1,822 | — | 1,822 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Equity funds subtotal | 1,275 | 1,822 | — | 3,097 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 1,014 | 33 | — | 1,047 | ||||||||||||||||||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 541 | — | 541 | ||||||||||||||||||||||||||||
Debt securities issued by foreign governments | — | 16 | — | 16 | ||||||||||||||||||||||||||||
Corporate debt securities | — | 778 | — | 778 | ||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | — | 357 | — | 357 | ||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 83 | — | 83 | ||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | — | 5 | — | 5 | ||||||||||||||||||||||||||||
Mutual funds | — | 47 | — | 47 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Fixed income subtotal | 1,014 | 1,860 | — | 2,874 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Direct lending securities | — | — | 13 | 13 | ||||||||||||||||||||||||||||
Other debt obligations | — | 18 | — | 18 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,851 | 3,700 | 13 | 6,564 | ||||||||||||||||||||||||||||
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
As of December 31, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Pledged assets for Zion decommissioning | ||||||||||||||||
Equity | ||||||||||||||||
Equity securities | 35 | — | — | 35 | ||||||||||||
Commingled funds | — | 30 | — | 30 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Equity funds subtotal | 35 | 30 | — | 65 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income | ||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 54 | 26 | — | 80 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 65 | — | 65 | ||||||||||||
Corporate debt securities | — | 314 | — | 314 | ||||||||||||
Federal agency mortgage-backed securities | — | 121 | — | 121 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 10 | — | 10 | ||||||||||||
Commingled funds | — | 20 | — | 20 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income subtotal | 54 | 556 | — | 610 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Direct lending securities | — | — | 37 | 37 | ||||||||||||
Other debt obligations | — | 13 | — | 13 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 89 | 599 | 37 | 725 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Rabbi trust investments | ||||||||||||||||
Cash equivalents | 2 | — | — | 2 | ||||||||||||
Mutual funds(d)(e) | 34 | — | — | 34 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Rabbi trust investments subtotal | 36 | — | — | 36 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Commodity Mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 857 | — | 857 | ||||||||||||
Economic hedges | — | 1,653 | 124 | 1,777 | ||||||||||||
Proprietary trading | — | 240 | 48 | 288 | ||||||||||||
Effect of netting and allocation of collateral(f) | — | (1,827 | ) | (28 | ) | (1,855 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Commodity Mark-to-market assets(g) | — | 923 | 144 | 1,067 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Interest rate mark-to-market derivative assets | — | 15 | — | 15 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total assets | 3,837 | 5,237 | 194 | 9,268 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Liabilities | ||||||||||||||||
Commodity Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges | — | (13 | ) | — | (13 | ) | ||||||||||
Economic hedges | (1 | ) | (1,137 | ) | (119 | ) | (1,257 | ) | ||||||||
Proprietary trading | — | (236 | ) | (28 | ) | (264 | ) | |||||||||
Effect of netting and allocation of collateral(f) | — | 1,295 | 20 | 1,315 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Commodity Mark-to-market liabilities(h) | (1 | ) | (91 | ) | (127 | ) | (219 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Interest rate mark-to-market liabilities | — | (19 | ) | — | (19 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Deferred compensation | — | (73 | ) | — | (73 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total liabilities | (1 | ) | (183 | ) | (127 | ) | (311 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Total net assets | $ | 3,836 | $ | 5,054 | $ | 67 | $ | 8,957 | ||||||||
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(a) | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. |
(b) |
|
|
Excludes net assets (liabilities) |
Excludes net assets of |
(d) | The mutual funds held by the Rabbi trusts include $60 million related to deferred compensation and $15 million related to Supplemental Executive Retirement Plan. These funds are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets. |
(e) | Excludes $27 million and $25 million of the cash surrender value of life insurance investments at March 31, 2012 and December 31, 2011, respectively. |
(f) | Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $426, $(627) million and $(37) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2012. Collateral received from counterparties, net of collateral paid to counterparties, totaled $532 million and $8 million allocated to Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2011. |
(g) | The Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $590 million and $92 million at March 31, 2012 and $503 million and $191 million at December 31, 2011, respectively, related to the fair value of Generation’s financial swap contract with ComEd. |
(h) | The Level 3 balance includes the current and noncurrent liability of $ 16 million and $125 million at March 31, 2012, respectively, and $9 million and $97 million at December 31, 2011, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2012 and 2011:
Three Months Ended March 31, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | |||||||||||||||
Balance as of December 31, 2011 | $ | 13 | $ | 37 | $ | 17 | $ | — | $ | 67 | ||||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||||||
Included in net income | — | — | 85 | (a) | — | 85 | ||||||||||||||
Included in regulatory assets | — | — | (35 | )(b) | — | (35 | ) | |||||||||||||
Change in collateral | — | — | (23 | ) | — | (23 | ) | |||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||
Purchases(c) | — | 6 | 316 | 14 | 336 | |||||||||||||||
Sales | — | (1 | ) | — | — | (1 | ) | |||||||||||||
Transfers out of Level 3 | — | (1 | ) | — | (1 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance as of March 31, 2012 | $ | 13 | $ | 42 | $ | 359 | $ | 14 | $ | 428 | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
The amount of total gains included in net income attributed to the change in unrealized losses related to assets and liabilities held for the three months ended March 31, 2012 | $ | — | $ | — | $ | 93 | $ | — | $ | 93 |
(a) | Includes the reclassification of $19 million of realized losses due to the settlement of derivative contracts recorded in results of operations. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
|
|
|
The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2011 and 2010:
Three Months Ended September 30, 2011 | Nuclear Decommissioning Trust Fund Investment | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Total | ||||||||||||
Balance as of June 30, 2011 | $ | — | $ | 34 | $ | (16 | ) | $ | 18 | |||||||
Total realized / unrealized (losses) | ||||||||||||||||
Included in income | — | — | (8 | )(a) | (8 | ) | ||||||||||
Included in other comprehensive income | — | — | (15 | )(b) | (15 | ) | ||||||||||
Included in regulatory assets | — | — | (18 | ) | (18 | ) | ||||||||||
Included in payable for Zion Station decommissioning | — | (3 | ) | — | (3 | ) | ||||||||||
Change in collateral | — | — | 8 | 8 | ||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||
Purchases | 6 | 17 | — | 23 | ||||||||||||
Sales | — | (10 | ) | — | (10 | ) | ||||||||||
Transfers out of Level 3 — Asset | — | — | 24 | 24 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Balance as of September 30, 2011 | $ | 6 | $ | 38 | $ | (25 | ) | $ | 19 | |||||||
|
|
|
|
|
|
|
| |||||||||
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 September 30, 2011 | $ | — | $ | — | $ | (5 | ) | $ | (5 | ) |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2011 | Nuclear Decommissioning Trust Fund Investment | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Total | ||||||||||||
Balance as of December 31, 2010 | $ | — | $ | — | $ | 50 | $ | 50 | ||||||||
Total realized / unrealized (losses) | ||||||||||||||||
Included in other comprehensive income | — | — | (27 | )(b) | (27 | ) | ||||||||||
Included in regulatory assets | — | — | (51 | ) | (51 | ) | ||||||||||
Change in collateral | — | — | 15 | 15 | ||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||
Purchases | 6 | 60 | 4 | 70 | ||||||||||||
Sales | — | (22 | ) | — | (22 | ) | ||||||||||
Transfers out of Level 3 — Asset | — | — | (16 | ) | (16 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Balance as of September 30, 2011 | $ | 6 | $ | 38 | $ | (25 | ) | $ | 19 | |||||||
|
|
|
|
|
|
|
| |||||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2011 | $ | — | $ | — | $ | 18 | $ | 18 |
Three Months Ended March 31, 2011 | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Total | |||||||||
Balance as of December 31, 2010 | $ | — | $ | 50 | 50 | |||||||
Included in net income | — | (13 | )(a) | (13 | ) | |||||||
Included in other comprehensive income | — | (9 | )(b) | (9 | ) | |||||||
Included in regulatory liabilities | — | 52 | (c) | 52 | ||||||||
Change in collateral | — | 5 | 5 | |||||||||
Purchases | 31 | — | 31 | |||||||||
Transfers out of Level 3 | — | (34 | ) | (34 | ) | |||||||
|
|
|
|
|
| |||||||
Balance as of March 31, 2011 | $ | 31 | $ | 51 | $ | 82 | ||||||
|
|
|
|
|
| |||||||
The amount of total gains included in net income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended March 31, 2011 | $ | — | $ | (7 | ) | (7 | ) |
(a) | Includes the reclassification of |
(b) |
|
Three Months Ended September 30, 2010 | Nuclear Decommissioning Trust Fund Investments(d) | Mark-to-Market Derivatives | Total | |||||||||
Balance as of June 30, 2010 | $ | 1 | $ | 67 | $ | 68 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in income | — | 30 | (a) | 30 | ||||||||
Included in other comprehensive income | — | 14 | (b) | 14 | ||||||||
Change in collateral | — | (14 | ) | (14 | ) | |||||||
Purchases, sales, issuances and settlements | ||||||||||||
Purchases | 12 | 4 | 16 | |||||||||
Sales | (1 | ) | — | (1 | ) | |||||||
Transfers out of Level 3 — Liability | — | 3 | 3 | |||||||||
|
|
|
|
|
| |||||||
Balance as of September 30, 2010 | $ | 12 | $ | 104 | $ | 116 | ||||||
|
|
|
|
|
| |||||||
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 September 30, 2010 | $ | — | $ | 34 | $ | 34 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2010 | Servicing Liability | Nuclear Decommissioning Trust Fund Investments(d) | Mark-to-Market Derivatives | Total | ||||||||||||
Balance as of December 31, 2009 | $ | (2 | ) | $ | — | $ | (44 | ) | $ | (46 | ) | |||||
Total realized / unrealized gains (losses) | ||||||||||||||||
Included in income | 2 | (c) | — | 110 | (a) | 112 | ||||||||||
Included in other comprehensive income | — | — | 21 | (b) | 21 | |||||||||||
Included in regulatory assets | — | — | (2 | ) | (2 | ) | ||||||||||
Change in collateral | — | — | (22 | ) | (22 | ) | ||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||
Purchases | — | 13 | 15 | 28 | ||||||||||||
Sales | — | (1 | ) | — | (1 | ) | ||||||||||
Transfers out of Level 3 — Liability | — | — | 26 | 26 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Balance as of September 30, 2010 | $ | — | $ | 12 | $ | 104 | $ | 116 | ||||||||
|
|
|
|
|
|
|
| |||||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2010 | $ | — | $ | — | $ | 112 | $ | 112 |
|
|
(c) |
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables presenttable presents 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 nine months ended September 30, 2011March 31, 2012 and 2010:2011:
Operating Revenue | Purchased Power | Fuel | Other, net | |||||||||||||
Total gains (losses) included in income for the three months ended September 30, 2011 | $ | (5 | ) | $ | (6 | ) | $ | 3 | $ | — | ||||||
Total gains (losses) included in income for the nine months ended September 30, 2011 | $ | 2 | $ | (3 | ) | $ | 1 | $ | — | |||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2011 | $ | 1 | $ | (9 | ) | $ | 3 | $ | — | |||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2011 | $ | 22 | $ | (7 | ) | $ | 3 | $ | — |
Three Months Ended March 31, 2012 | Operating Revenues | Purchased Power and Fuel | ||||||
Total gains (losses) included in net income for the three months ended March 31, 2012 | $ | 87 | $ | (2 | ) | |||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2012 | $ | 104 | $ | (11 | ) |
Operating Revenue | Purchased Power | Fuel | Other, net | |||||||||||||
Total gains (losses) included in income for the three months ended September 30, 2010 | $ | (6 | ) | $ | 26 | $ | 10 | $ | — | |||||||
Total gains included in income for the nine months ended September 30, 2010 | $ | 7 | $ | 62 | $ | 41 | $ | 2 | ||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2010 | $ | (1 | ) | $ | 24 | $ | 11 | $ | — | |||||||
Change in the unrealized gains relating to assets and liabilities for the three months ended September 30, 2010 | $ | 22 | $ | 57 | $ | 33 | $ | — |
Three Months Ended March 31, 2011 | Operating Revenues | Purchased Power and Fuel | ||||||
Total losses included in net income for the three months ended March 31, 2011 | $ | (3 | ) | $ | (10 | ) | ||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2011 | $ | 4 | $ | (11 | ) |
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 September 30, 2011March 31, 2012 and December 31, 2010:2011:
As of September 30, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 115 | $ | — | $ | — | $ | 115 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 320 | 20 | — | 340 | ||||||||||||
Equity securities(b) | 1,147 | — | — | 1,147 | ||||||||||||
Commingled funds(c) | — | 1,791 | — | 1,791 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 598 | 91 | — | 689 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 549 | — | 549 | ||||||||||||
Corporate debt securities | — | 701 | — | 701 | ||||||||||||
Federal agency mortgage-backed securities | — | 901 | — | 901 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 116 | — | 116 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 5 | — | 5 | ||||||||||||
Other debt obligations | — | 64 | 6 | 70 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 2,065 | 4,238 | 6 | 6,309 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||
Equity securities | 43 | — | — | 43 | ||||||||||||
Commingled funds(c) | — | 67 | — | 67 | ||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 114 | 22 | — | 136 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 49 | — | 49 | ||||||||||||
Corporate debt securities | — | 291 | — | 291 | ||||||||||||
Federal agency mortgage-backed securities | — | 123 | — | 123 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 12 | — | 12 | ||||||||||||
Private equity | — | — | 38 | 38 | ||||||||||||
Other debt obligations | — | 2 | — | 2 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning subtotal(e) | 157 | 566 | 38 | 761 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Rabbi trust investments(f)(g) | 4 | — | — | 4 | ||||||||||||
Mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 413 | 664 | 1,077 | ||||||||||||
Other derivatives | — | 1,194 | 15 | 1,209 | ||||||||||||
Proprietary trading | — | 165 | 52 | 217 | ||||||||||||
Effect of netting and allocation of collateral(h) | (1 | ) | (1,058 | ) | (17 | ) | (1,076 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Mark-to-market assets(i) | (1 | ) | 714 | 714 | 1,427 | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total assets | 2,340 | 5,518 | 758 | 8,616 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Liabilities | ||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges(j) | — | (141 | ) | — | (141 | ) | ||||||||||
Other derivatives | (1 | ) | (651 | ) | (16 | ) | (668 | ) | ||||||||
Proprietary trading | — | (161 | ) | (26 | ) | (187 | ) | |||||||||
Effect of netting and allocation of collateral(h) | 1 | 910 | 18 | 929 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Mark-to-market liabilities | — | (43 | ) | (24 | ) | (67 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Deferred compensation | — | (17 | ) | — | (17 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total liabilities | — | (60 | ) | (24 | ) | (84 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Total net assets | $ | 2,340 | $ | 5,458 | $ | 734 | $ | 8,532 | ||||||||
|
|
|
|
|
|
|
|
As of March 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets | ||||||||||||||||
Cash equivalents(a) | $ | 60 | $ | — | $ | — | $ | 60 | ||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||
Cash equivalents | 428 | — | — | 428 | ||||||||||||
Equity | ||||||||||||||||
Equity securities | 1,460 | — | — | 1,460 | ||||||||||||
Commingled funds | — | 2,027 | — | 2,027 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Equity funds subtotal | 1,460 | 2,027 | — | 3,487 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income | ||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 941 | 1 | — | 942 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 328 | — | 328 | ||||||||||||
Debt securities issued by foreign governments | — | 67 | — | 67 | ||||||||||||
Corporate debt securities | — | 1,534 | — | 1,534 | ||||||||||||
Federal agency mortgage-backed securities | — | 55 | — | 55 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 39 | — | 39 | ||||||||||||
Residential mortgage-backed securities (non-agency) | — | 8 | — | 8 | ||||||||||||
Mutual funds | — | 2 | — | 2 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income subtotal | 941 | 2,034 | — | 2,975 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Direct lending securities | — | — | 13 | 13 | ||||||||||||
Other debt obligations | — | 11 | — | 11 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,829 | 4,072 | 13 | 6,914 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||
Equity | ||||||||||||||||
Equity securities | 26 | — | — | 26 | ||||||||||||
Commingled funds | — | 22 | — | 22 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Equity funds subtotal | 26 | 22 | — | 48 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income | ||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 63 | 24 | — | 87 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 53 | — | 53 | ||||||||||||
Corporate debt securities | — | 325 | — | 325 | ||||||||||||
Federal agency mortgage-backed securities | — | 100 | — | 100 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 10 | — | 10 | ||||||||||||
Commingled funds | — | 40 | — | 40 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income subtotal | 63 | 552 | — | 615 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Direct lending securities | — | — | 42 | 42 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 89 | 574 | 42 | 705 | ||||||||||||
|
|
|
|
|
|
|
|
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 | ||||||||||||||||||||||||||||
As of March 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
Rabbi trust investments(d)(e) | 5 | — | — | 5 | ||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||
Economic hedges | 1,988 | 6,913 | 1,672 | 10,573 | ||||||||||||||||||||||||||||
Proprietary trading | 3,341 | 6,427 | 219 | 9,987 | ||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | (5,329 | ) | (11,418 | ) | (370 | ) | (17,117 | ) | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(d) | 2,018 | 4,358 | — | 6,376 | ||||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal(g) | — | 1,922 | 1,521 | 3,443 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||||||||||||||||||
Equity securities | 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 | |||||||||||||||||||||||||||
Interest Rate mark-to-market derivative assets | — | 105 | — | 105 | ||||||||||||||||||||||||||||
Other investments | 3 | — | 14 | 17 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total assets | 2,690 | 5,734 | 1,053 | 9,477 | 2,986 | 6,673 | 1,590 | 11,249 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||
Cash flow hedges | — | (45 | ) | — | (45 | ) | ||||||||||||||||||||||||||
Other derivatives | (2 | ) | (667 | ) | (25 | ) | (694 | ) | ||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||
Economic hedges | (2,527 | ) | (5,659 | ) | (308 | ) | (8,494 | ) | ||||||||||||||||||||||||
Proprietary trading | — | (233 | ) | (21 | ) | (254 | ) | (3,457 | ) | (6,146 | ) | (364 | ) | (9,967 | ) | |||||||||||||||||
Effect of netting and allocation of collateral(h) | 1 | 914 | 23 | 938 | ||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | 5,755 | 10,791 | 333 | 16,879 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Mark-to-market liabilities | (1 | ) | (31 | ) | (23 | ) | (55 | ) | ||||||||||||||||||||||||
Commodity mark-to-market liabilities subtotal | (229 | ) | (1,014 | ) | (339 | ) | (1,582 | ) | ||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities | — | (54 | ) | — | (54 | ) | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Deferred compensation | — | (20 | ) | — | (20 | ) | — | (20 | ) | — | (20 | ) | ||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total liabilities | (1 | ) | (51 | ) | (23 | ) | (75 | ) | (229 | ) | (1,088 | ) | (339 | ) | (1,656 | ) | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total net assets | $ | 2,689 | $ | 5,683 | $ | 1,030 | $ | 9,402 | $ | 2,757 | $ | 5,585 | $ | 1,251 | $ | 9,593 | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
As of December 31, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 466 | $ | — | $ | — | $ | 466 | ||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||
Cash equivalents | 562 | — | — | 562 | ||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||
Equity securities | 1,275 | — | — | 1,275 | ||||||||||||||||||||||||||||
Commingled funds | — | 1,822 | — | 1,822 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Equity funds subtotal | 1,275 | 1,822 | — | 3,097 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 1,014 | 33 | — | 1,047 | ||||||||||||||||||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 541 | — | 541 | ||||||||||||||||||||||||||||
Debt securities issued by foreign governments | — | 16 | — | 16 | ||||||||||||||||||||||||||||
Corporate debt securities | — | 778 | — | 778 | ||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | — | 357 | — | 357 | ||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 83 | — | 83 | ||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | — | 5 | — | 5 | ||||||||||||||||||||||||||||
Mutual funds | — | 47 | — | 47 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Fixed income subtotal | 1,014 | 1,860 | — | 2,874 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Direct lending securities | — | — | 13 | 13 | ||||||||||||||||||||||||||||
Other debt obligations | — | 18 | — | 18 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,851 | 3,700 | 13 | 6,564 | ||||||||||||||||||||||||||||
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
As of December 31, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||
Equity | ||||||||||||||||
Equity securities | 35 | — | — | 35 | ||||||||||||
Commingled funds | — | 30 | — | 30 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Equity funds subtotal | 35 | 30 | — | 65 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income | ||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 54 | 26 | — | 80 | ||||||||||||
Debt securities issued by states of the United States and political subdivisions of the states | — | 65 | — | 65 | ||||||||||||
Corporate debt securities | — | 314 | — | 314 | ||||||||||||
Federal agency mortgage-backed securities | — | 121 | — | 121 | ||||||||||||
Commercial mortgage-backed securities (non-agency) | — | 10 | — | 10 | ||||||||||||
Commingled funds | — | 20 | — | 20 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Fixed income subtotal | 54 | 556 | — | 610 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Direct lending securities | — | — | 37 | 37 | ||||||||||||
Other debt obligations | — | 13 | — | 13 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 89 | 599 | 37 | 725 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Rabbi trust investments(d)(e) | 4 | — | — | 4 | ||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||
Cash flow hedges | — | 857 | 694 | 1,551 | ||||||||||||
Other derivatives | — | 1,653 | 124 | 1,777 | ||||||||||||
Proprietary trading | — | 240 | 48 | 288 | ||||||||||||
Effect of netting and allocation of collateral(f) | — | (1,827 | ) | (28 | ) | (1,855 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Commodity Mark-to-market assets subtotal(g) | — | 923 | 838 | 1,761 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total assets | 3,410 | 5,222 | 888 | 9,520 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Liabilities | ||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||
Cash flow hedges | — | (13 | ) | — | (13 | ) | ||||||||||
Other derivatives | (1 | ) | (1,137 | ) | (13 | ) | (1,151 | ) | ||||||||
Proprietary trading | — | (236 | ) | (28 | ) | (264 | ) | |||||||||
Effect of netting and allocation of collateral(f) | — | 1,295 | 20 | 1,315 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Commodity Mark-to-market liabilities subtotal | (1 | ) | (91 | ) | (21 | ) | (113 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Interest rate mark-to-market derivative liabilities | — | (19 | ) | — | (19 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Deferred compensation | — | (18 | ) | — | (18 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total liabilities | (1 | ) | (128 | ) | (21 | ) | (150 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Total net assets | $ | 3,409 | $ | 5,094 | $ | 867 | $ | 9,370 | ||||||||
|
|
|
|
|
|
|
|
(a) | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. |
(b) |
|
|
Excludes net assets (liabilities) |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Excludes net assets of |
The mutual funds held by the Rabbi trusts |
Excludes |
Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral |
The Level 3 balance includes current and noncurrent assets for Generation of |
|
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 nine months ended September 30, 2011March 31, 2012 and September 30, 2010:December 31, 2011:
Three Months Ended September 30, 2011 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Total | ||||||||||||
Balance as of June 30, 2011 | $ | — | $ | 34 | $ | 776 | $ | 810 | ||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||
Included in income | — | — | (8 | )(a) | (8 | ) | ||||||||||
Included in other comprehensive income | — | — | (110 | )(b) | (110 | ) | ||||||||||
Included in payable for Zion Station decommissioning | — | (3 | ) | — | (3 | ) | ||||||||||
Change in collateral | — | — | 8 | 8 | ||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||
Purchases | 6 | 17 | — | 23 | ||||||||||||
Sales | — | (10 | ) | — | (10 | ) | ||||||||||
Transfers out of Level 3 — Asset | — | — | 24 | 24 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Balance as of September 30, 2011 | $ | 6 | $ | 38 | $ | 690 | $ | 734 | ||||||||
|
|
|
|
|
|
|
| |||||||||
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 September 30, 2011 | $ | — | $ | — | $ | (5 | ) | $ | (5 | ) |
Three Months Ended March 31, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | |||||||||||||||
Balance as of December 31, 2011 | $ | 13 | $ | 37 | $ | 817 | $ | — | $ | 867 | ||||||||||
Total unrealized / realized gains (losses) | ||||||||||||||||||||
Included in income | — | — | 74 | (a) | — | 74 | ||||||||||||||
Included in other comprehensive income | — | — | (1 | )(b) | — | (1 | ) | |||||||||||||
Change in collateral | — | — | (23 | ) | — | (23 | ) | |||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||
Purchases(c) | — | 6 | 316 | 14 | 336 | |||||||||||||||
Sales | — | (1 | ) | — | — | (1 | ) | |||||||||||||
Transfers out of Level 3 | — | — | (1 | ) | — | (1 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance as of March 31, 2012 | $ | 13 | $ | 42 | $ | 1,182 | $ | 14 | $ | 1,251 | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the year ended March 31, 2012 | $ | — | $ | — | $ | 93 | $ | — | $ | 93 |
(a) | Includes the reclassification of $19 million of realized losses due to the settlement of derivative contracts recorded in results of operations. |
(b) | Includes $135 million of increases in fair value and $147 million of realized losses due to settlements during 2012 of Generation’s financial swap contract with ComEd, which eliminates upon consolidation in Exelon’s Consolidated Financial Statements. |
(c) | Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2011 | Nuclear Decommissioning Trust Fund Investments | 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 other comprehensive income | — | — | (343 | )(b) | (343 | ) | ||||||||||
Change in collateral | — | — | 15 | 15 | ||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||
Purchases | 6 | 60 | 4 | 70 | ||||||||||||
Sales | — | (22 | ) | — | (22 | ) | ||||||||||
Transfers out of Level 3 — Asset | — | — | (16 | ) | (16 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Balance as of September 30, 2011 | $ | 6 | $ | 38 | $ | 690 | $ | 734 | ||||||||
|
|
|
|
|
|
|
| |||||||||
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2011 | $ | — | $ | — | $ | 18 | $ | 18 |
Three Months Ended March 31, 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 losses | ||||||||||||
Included in net income | — | (13 | )(a) | (13 | ) | |||||||
Included in other comprehensive income | — | (55 | )(b) | (55 | ) | |||||||
Change in collateral | — | 5 | 5 | |||||||||
Purchases | 31 | — | 31 | |||||||||
Transfers out of Level 3 | — | (34 | ) | (34 | ) | |||||||
|
|
|
|
|
| |||||||
Balance as of March 31, 2011 | $ | 31 | $ | 933 | $ | 964 | ||||||
|
|
|
|
|
| |||||||
The amount of total losses included in income attributed to the change in unrealized losses related to assets and liabilities held for the three months ended March 31, 2011 | $ | — | $ | (7 | ) | $ | (7 | ) |
(a) | Includes the reclassification of |
(b) | Includes |
Three Months Ended September 30, 2010 | Nuclear Decommissioning Trust Fund Investments (c) | Mark-to-Market Derivatives | Total | |||||||||
Balance as of June 30, 2010 | $ | 1 | $ | 1,086 | $ | 1,087 | ||||||
Total realized / unrealized losses | ||||||||||||
Included in income | — | 30 | (a) | 30 | ||||||||
Included in other comprehensive income | — | 131 | (b) | 131 | ||||||||
Changes in collateral | — | (14 | ) | (14 | ) | |||||||
Purchases, sales, issuances and settlements | ||||||||||||
Purchases | 12 | 4 | 16 | |||||||||
Sales | (1 | ) | — | (1 | ) | |||||||
Transfers out of Level 3 — Liability | — | 3 | 3 | |||||||||
|
|
|
|
|
| |||||||
Balance as of September 30, 2010 | $ | 12 | $ | 1,240 | $ | 1,252 | ||||||
|
|
|
|
|
| |||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of September 30, 2010 | $ | — | $ | 34 | $ | 34 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2010 | Nuclear Decommissioning Trust Fund Investments(c) | Mark-to-Market Derivatives | Total | |||||||||
Balance as of December 31, 2009 | $ | — | $ | 931 | $ | 931 | ||||||
Total realized / unrealized gains | ||||||||||||
Included in income | — | 110 | (a) | 110 | ||||||||
Included in other comprehensive income | — | 180 | (b) | 180 | ||||||||
Changes in collateral | — | (22 | ) | (22 | ) | |||||||
Purchases, sales, issuances and settlements | ||||||||||||
Purchases | 13 | 15 | 28 | |||||||||
Sales | (1 | ) | — | (1 | ) | |||||||
Transfers out of Level 3 — Liability | — | 26 | 26 | |||||||||
|
|
|
|
|
| |||||||
Balance as of September 30, 2010 | $ | 12 | $ | 1,240 | $ | 1,252 | ||||||
|
|
|
|
|
| |||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of September 30, 2010 | $ | — | $ | 112 | $ | 112 |
|
|
|
The following tables presenttable presents 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 nine months ended September 30, 2011March 31, 2012 and 2010:2011:
Operating Revenue | Purchased Power | Fuel | ||||||||||
Total gains (losses) included in income for the three months ended September 30, 2011 | $ | (5 | ) | $ | (6 | ) | $ | 3 | ||||
Total gains (losses) included in income for the nine months ended September 30, 2011 | $ | 2 | $ | (3 | ) | $ | 1 | |||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2011 | $ | 1 | $ | (9 | ) | $ | 3 | |||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2011 | $ | 22 | $ | (7 | ) | $ | 3 |
Three Months Ended March 31, 2012 | Operating Revenues | Purchased Power and Fuel | ||||||
Total gains (losses) included in net income for the three months ended March 31, 2012 | $ | 76 | $ | (2 | ) | |||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2012 | $ | 104 | $ | (11 | ) |
Operating Revenue | Purchased Power | Fuel | ||||||||||
Total gains (losses) included in income for the three months ended September 30, 2010 | $ | (6 | ) | $ | 26 | $ | 10 | |||||
Total gains included in income for the nine months ended September 30, 2010 | $ | 7 | $ | 62 | $ | 41 | ||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2010 | $ | (1 | ) | $ | 24 | $ | 11 | |||||
Change in the unrealized gains relating to assets and liabilities held for the nine months ended September 30, 2010 | $ | 22 | $ | 57 | $ | 33 |
Three Months Ended March 31, 2011 | Operating Revenues | Purchased Power and Fuel | ||||||
Total losses included in net income for the three months ended March 31, 2011 | $ | (3 | ) | $ | (10 | ) | ||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2011 | $ | 4 | $ | (11 | ) |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
ComEd
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 September 30, 2011March 31, 2012 and December 31, 2010:2011:
As of September 30, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
As of March 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 830 | $ | — | $ | — | $ | 830 | $ | 3 | $ | — | $ | — | $ | 3 | ||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||
Cash equivalents | 1 | — | — | 1 | ||||||||||||||||||||||||||||
Mutual funds | 21 | — | — | 21 | 15 | — | — | 15 | ||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Rabbi trust investment subtotal | 16 | — | — | 16 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total assets | 851 | — | — | 851 | 19 | — | — | 19 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (8 | ) | — | (8 | ) | — | (9 | ) | — | (9 | ) | ||||||||||||||||||||
Mark-to-market derivative liabilities(b)(c) | — | — | (712 | ) | (712 | ) | — | — | (823 | ) | (823 | ) | ||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total liabilities | — | (8 | ) | (712 | ) | (720 | ) | — | (9 | ) | (823 | ) | (832 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total net assets (liabilities) | $ | 851 | $ | (8 | ) | $ | (712 | ) | $ | 131 | $ | 19 | $ | (9 | ) | $ | (823 | ) | $ | (813 | ) | |||||||||||
|
|
|
|
|
|
|
|
As of December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
As of December 31, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 1 | $ | — | $ | — | $ | 1 | $ | 173 | $ | — | $ | — | $ | 173 | ||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||
Cash equivalents | 2 | — | — | 2 | ||||||||||||||||||||||||||||
Mutual funds | 23 | — | — | 23 | 19 | — | — | 19 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Rabbi trust investment subtotal | 23 | — | — | 23 | 21 | — | — | 21 | ||||||||||||||||||||||||
Mark-to-market derivative assets | — | — | 4 | 4 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total assets | 24 | — | 4 | 28 | 194 | — | — | 194 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (8 | ) | — | (8 | ) | — | (8 | ) | — | (8 | ) | ||||||||||||||||||||
Mark-to-market derivative liabilities | — | — | (975 | ) | (975 | ) | — | — | (800 | ) | (800 | ) | ||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total liabilities | — | (8 | ) | (975 | ) | (983 | ) | — | (8 | ) | (800 | ) | (808 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total net assets (liabilities) | $ | 24 | $ | (8 | ) | $ | (971 | ) | $ | (955 | ) | $ | 194 | $ | (8 | ) | $ | (800 | ) | $ | (614 | ) | ||||||||||
|
|
|
|
|
|
|
|
(a) | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. |
(b) | The Level 3 balance includes the current and noncurrent liability of |
(c) | The Level 3 balance includes the current and noncurrent liability of |
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 ninethree months ended September 30, 2011March 31, 2012 and 2010:2011:
Three Months Ended September 30, 2011 | Mark-to-Market Derivatives | |||
Balance as of June 30, 2011 | $ | (788 | ) | |
Total realized / unrealized gains included in regulatory assets(a)(b) | 76 | |||
|
| |||
Balance as of September 30, 2011 | $ | (712 | ) | |
|
|
Nine Months Ended September 30, 2011 | Mark-to-Market Derivatives | |||
Balance as of December 31, 2010 | $ | (971 | ) | |
Total realized / unrealized gains included in regulatory assets(a)(b) | 259 | |||
|
| |||
Balance as of September 30, 2011 | $ | (712 | ) | |
|
|
Three Months Ended March 31, 2012 | Mark-to-Market Derivatives | |||
Balance as of December 31, 2011 | $ | (800 | ) | |
Total realized / unrealized losses included in regulatory assets(a)(b) | (23 | ) | ||
|
| |||
Balance as of March 31, 2012 | $ | (823 | ) | |
|
|
(a) | Includes |
(b) | Includes |
Three Months Ended September 30, 2010 | Mark-to-Market Derivatives | |||
Balance as of June 30, 2010 | $ | (1,010 | ) | |
Total realized / unrealized gains included in regulatory assets(a) | (117 | ) | ||
|
| |||
Balance as of September 30, 2010 | $ | (1,127 | ) | |
|
|
Nine Months Ended September 30, 2010 | Mark-to-Market Derivatives | |||
Balance as of December 31, 2009 | $ | (971 | ) | |
Total realized / unrealized losses included in regulatory assets(a) | (156 | ) | ||
|
| |||
Balance as of September 30, 2010 | $ | (1,127 | ) | |
|
|
Three Months Ended March 31, 2011 | Mark-to-Market Derivatives | |||
Balance as of December 31, 2010 | $ | (971 | ) | |
Total unrealized / realized gains included in regulatory assets(a)(b) | 96 | |||
|
| |||
Balance as of March 31, 2011 | $ | (875 | ) | |
|
|
(a) | Includes |
(b) | Includes an increase in fair value of $51 million associated with 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)
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 September 30, 2011March 31, 2012 and December 31, 2010:2011:
As of September 30, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
As of March 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||
Cash equivalents | $ | 494 | $ | — | $ | — | $ | 494 | $ | 53 | $ | — | $ | — | $ | 53 | ||||||||||||||||
Rabbi trust investments — mutual funds(b)(c) | 8 | — | — | 8 | 9 | — | — | 9 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total assets | 502 | — | — | 502 | 62 | — | — | 62 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (21 | ) | — | (21 | ) | — | (21 | ) | — | (21 | ) | ||||||||||||||||||||
Mark-to-market derivative liabilities(d) | — | — | (3 | ) | (3 | ) | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total liabilities | — | (21 | ) | (3 | ) | (24 | ) | — | (21 | ) | — | (21 | ) | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total net assets (liabilities) | $ | 502 | $ | (21 | ) | $ | (3 | ) | $ | 478 | $ | 62 | $ | (21 | ) | $ | — | $ | 41 | |||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
As of December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
As of December 31, 2011 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||
Assets | �� | |||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 499 | $ | — | $ | — | $ | 499 | $ | 175 | $ | — | $ | — | $ | 175 | ||||||||||||||||
Rabbi trust investments — mutual funds(b)(c) | 7 | — | — | 7 | 9 | — | — | 9 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total assets | 506 | — | — | 506 | 184 | — | — | 184 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (23 | ) | — | (23 | ) | — | (21 | ) | — | (21 | ) | ||||||||||||||||||||
Mark-to-market derivative liabilities(d) | — | — | (9 | ) | (9 | ) | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total liabilities | — | (23 | ) | (9 | ) | (32 | ) | — | (21 | ) | — | (21 | ) | |||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total net assets (liabilities) | $ | 506 | $ | (23 | ) | $ | (9 | ) | $ | 474 | $ | 184 | $ | (21 | ) | $ | — | $ | 163 | |||||||||||||
|
|
|
|
|
|
|
|
(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 |
(c) | Excludes $14 million and $13 million of the cash surrender value of life insurance investments at |
|
PECO had no Level 3 assets or liabilities measured at fair value on a recurring basis during the three months ended March 31, 2012.
The following tables presenttable presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2011 and 2010:March 31, 2011:
Three Months Ended September 30, 2011 | Mark-to-Market Derivatives | |||
Balance as of June 30, 2011 | $ | (4 | ) | |
Total realized gains included in regulatory assets | 1 | |||
|
| |||
Balance as of September 30, 2011 | $ | (3 | ) | |
|
|
Three Months Ended March 31, 2011 | Mark-to-Market Derivatives | |||
Balance as of December 31, 2010 | $ | (9 | ) | |
Total realized / unrealized gains (losses) | 2 | (a) | ||
|
| |||
Balance as of March 31, 2011 | $ | (7 | ) | |
|
|
(a) | Includes a $1 million increase related to the settlement of PECO’s block contract with Generation, which eliminates upon consolidation in Exelon’s Consolidated Financial Statements. |
BGE
Assets and liabilities measured at fair value on BGE’s Consolidated Balance Sheets on a recurring basis are limited to cash equivalents in the amount of $52 million classified as a Level 1 investment.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2011 | Mark-to-Market Derivatives | |||
Balance as of December 31, 2010 | $ | (9 | ) | |
Total realized gains included in regulatory assets | 6 | (a) | ||
|
| |||
Balance as of September 30, 2011 | $ | (3 | ) | |
|
|
|
There were no changes in fair value for mark-to-market derivatives during the three months ended September 30, 2010.
Nine Months Ended September 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 September 30, 2010 | $ | (9 | ) | $ | — | $ | (9 | ) | ||||
|
|
|
|
|
|
|
|
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, PECO and PECO)BGE). 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.funds and Treasury bills. 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.markets and other alternative investments. 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 2.1.
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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.
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2.
CommingledEquity and fixed income commingled funds which are similar toand fixed income 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-termfixed income commingled and mutual 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 equity 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. Commingled and mutual funds are categorized in Level 2 because the fair value of the funds are based on NAVs per fund share (the unit of
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
account), primarily derived from the quoted prices in active markets on the underlying equity securities. See Note 910 — Nuclear Decommissioning for further discussion on the NDT fund investments.
Direct lending funds are investments in managed funds which invest in private companies for long-term capital appreciation. The fair value of these securities is determined using either an enterprise value model or a bond valuation model. Investments in direct lending funds are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models.
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 fairinvestments are in fixed-income commingled funds and mutual funds, including short-term investment funds. These funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. The values of some of these funds are publicly quoted. For fixed-income commingled funds and mutual funds which are not publicly quoted, the sharesfund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds are based on observable market prices and, therefore, have been categorized inas Level 2. Fixed-income commingled funds and mutual funds which are publicly quoted, such as money market funds, have been categorized as Level 1 ingiven the fair value hierarchy.clear observability of the prices.
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 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 Level 2 and Level 1 generally do not occur. Transfers in and out of Level 2 and Level 3 generally occur when the contract tenure becomes more observable.
Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon uses a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are discounted based on current forward curves and netted to determinedetermines the current fair value.value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market’s expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters such as interest rates and volatility.parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 67 — Derivative Financial Instruments for further discussion on mark-to-market derivatives.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 LiabilityAdditional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd)
For valuations that include both observable and PECO). PECOunobservable inputs, if the unobservable input is partydetermined to an agreement with abe 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. 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 executive officer, chief financial institution under which it transferred an undivided interest, adjusted daily, in customer accounts receivables designated underofficer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The RMC reports to the agreement in exchangeRisk Oversight Committee of the Exelon Board of Directors on the scope of the risk management activities and is responsible 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 recordedapproving all valuation procedures at Exelon. Forward price curves for the agreementpower market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in accordancethe valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, 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 end of the reporting period the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 generally do not occur. Transfers into Level 2 from Level 3 generally occur when the contract tenure becomes more observable.
Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The most significant position is the long term intercompany swap with the applicable authoritative guidance for servicing of financial assets.ComEd, which is further discussed in Note 7 — Derivative Financial Instruments. The servicing liability was included in other current liabilities in Exelon’s and PECO’s Consolidated Balance Sheets. Thecalculated fair value includes marketability discounts for margining provisions and notional size. Generation’s remaining Level 3 balance generally consists of forward sales and purchases of power and natural gas, coal purchases, and transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, Generation and ComEd, and credit enhancements.
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by the traders and portfolio managers considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the liability was determinedderivatives depends on a number of factors including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using internal estimates based on provisions inrisk free interest rates with adjustments to reflect the agreement, which were categorized as Level 3 inputs incredit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price is generally a product of the fair value hierarchy. The servicing liability was released in accordance with guidance on accounting for transfers of financial assets that was adopted on January 1, 2010.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are highly liquid and prices are observable for up to three years in the future. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not substantiate the majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is generally less than $4 and $.25 for power and natural gas respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrant’s mark-to-market derivative assets and liabilities.
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. See Note 7 — Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. The table below discloses the significant inputs to the forward curve used to value these positions.
Type of trade | Fair Value at March 31, 2012 | Valuation Technique | Unobservable Input | Range | ||||||||
Mark-to-market derivatives — Economic Hedges (Generation)(a) | $ | 682 | Discounted Cash Flow | Forward power price | $14 - $ 71 | |||||||
Discounted Cash Flow | Forward gas price | $1.95 - $3.08 | ||||||||||
Option Model | Volatility percentage | 40% - 60% | ||||||||||
Mark-to-market derivatives — Proprietary trading (Generation) (a) | $ | (145) | Discounted Cash Flow | Forward power price | $ 17 - $ 71 | |||||||
Option Model | Volatility percentage | 20% - 60% | ||||||||||
Mark-to-market derivatives — Transactions with affiliates (Generation and ComEd) (b) | $ | 682 | Discounted Cash Flow | Marketability reserve | 8.2% - 10.8% | |||||||
Mark-to-market derivatives (ComEd) | $ | (141 | ) | Discounted Cash Flow | Forward heat rate(c) | 6.5% - 8 % | ||||||
Marketability reserve | 3.5% - 8.2 % | |||||||||||
Renewable factor | 84% - 121 % |
a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. |
b) | Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $590 million and $92 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, which eliminates in consolidation. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
c) | Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery. |
The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.
6.7. Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and PECO)BGE)
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.
Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE)
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,value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge, and fair value hedge. For commodity transactions, effective with the date of merger with Constellation, Generation will no longer utilize the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. None of Constellation’s designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all economic hedges are recognized on the balance sheetfor commodities will be recorded at their fair value unless they qualifythrough earnings for the normal purchases and normal sales exception.combined company going forward, referred to as economic hedges in the following tables. 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 forcertain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 18 of the 2010Exelon 2011 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)COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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,derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights.
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
hedges commodity price risk on a ratable basis over three-year periods. As of September 30, 2011,March 31, 2012, the percentage of expected generation hedged was 97%-100%95%-98%, 85%-88%68%-71%, and 56%-59%40%-43% for the remainder of 2011, 2012, 2013 and 2013,2014, 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 floweconomic hedges other derivatives and certain non-derivative contracts including sales to ComEd, PECO and PECOBGE 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,process, which are further discussed in Note 2 of the 2010Exelon 2011 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 beenwas originally designated by Generation as a cash flow hedge. Consequently,As discussed previously, effective with the date of merger with Constellation, Generation de-designated this swap as a cash flow hedge and began recording changes in fair value through current earnings as of that date. Generation records the fair value of the swap on its balance sheet and recordsoriginally recorded changes in fair value to OCI. The value frozen in OCI as of the date of merger for this swap will be reclassified into Generation’s earnings as the swap settles. ComEd has not elected hedge accounting
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
for this derivative financial instrument. ComEd records the fair value of the swap on its balance sheet, however, sinceSince the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates, and therefore, the change in fair value each period is recorded by ComEd as a regulatory asset or liability.liability on ComEd’s Consolidated Balance Sheets. See Note 2 of the 2010Exelon 2011 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 procurement process outlined in its PAPUC-approved DSP Program, which is further discussed in Note 34 — 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 contracts and block contracts. PECO’s full requirements contracts and block contracts, which
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 beingwere amortized over the terms of the contracts, which beganended on January 1,December 31, 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 either qualify for the normal purchases and normal sales scope exception and have been designated as such.such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 20102011 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 20102011 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 coversis designed to cover 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 profitwith the intent of benefiting from shifts or changes in market price changesprices as opposed to those entered into with the intent of hedging an exposure and isor managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of 1,6791,888 GWh and 4,5081,333 GWh for the three and nine months ended September 30,March 31, 2012 and 2011, respectively, and 1,077 GWh and 2,885 GWh for the three and nine months ended September 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 and BGE do not enter into derivatives for proprietary trading purposes.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Interest Rate Risk (Exelon, Generation, ComEd, PECO and PECO)BGE)
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. AFor interest rate 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 interest rate transaction occurs. For interest rate hedges that qualify and are designated as fair value hedges, only the ineffective portion of the derivative gain or loss will impact earnings. Assuming the fair value and cash flow hedges are effective, a hypothetical 10%50 bps increase in the interest rates associated with variable-rate debt and interest rate swaps would result in less than a $1 million decrease in each of Exelon’s, ComEd’sGeneration’s and PECO’s pre-tax income for the three months ended September 30, 2011.March 31, 2012. Below is a summary of the interest rate hedges as of March 31, 2012.
Generation | Other | Exelon | ||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges (a) | Proprietary Trading (a) | Subtotal | Derivatives Designated as Hedging Instruments | Total | ||||||||||||||||||
Mark-to-market derivative assets (Current Assets) | $ | — | $ | 3 | $ | 18 | $ | 21 | $ | — | $ | 21 | ||||||||||||
Mark-to-market derivative assets (Noncurrent Assets) | 42 | 12 | 30 | 84 | 14 | 98 | ||||||||||||||||||
|
| |||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 42 | $ | 15 | $ | 48 | $ | 105 | $ | 14 | $ | 119 | ||||||||||||
|
| |||||||||||||||||||||||
Mark-to-market derivative liabilities (Current Liabilities) | $ | — | $ | (2 | ) | $ | (18 | ) | $ | (20 | ) | $ | — | $ | (20 | ) | ||||||||
Mark-to-market derivative liabilities (Noncurrent Liabilities) | (3 | ) | — | (31 | ) | (34 | ) | — | (34 | ) | ||||||||||||||
|
| |||||||||||||||||||||||
Total mark-to-market derivative liabilities | $ | (3 | ) | $ | (2 | ) | $ | (49 | ) | $ | (54 | ) | $ | — | $ | (54 | ) | |||||||
|
| |||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 39 | $ | 13 | $ | (1 | ) | $ | 51 | $ | 14 | $ | 65 | |||||||||||
|
|
(a) | Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the economic hedge and proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. The company does not utilize interest rate derivatives with the objective of benefiting from shifts or change in market interest rates. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 | ||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Interest expense | $ | 1 | $ | 7 | $ | (1 | ) | $ | (7 | ) |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||
Income Statement Classification | 2012 | 2011 | 2012 | 2011 | ||||||||||||
Interest expense(a) | $ | (3 | ) | $ | (2 | ) | $ | 1 | $ | 2 |
(a) | For the period ended March 31, 2012, the (loss) on the swaps in the table above includes pre-tax losses of $1 million related to changes in fair value hedges, which is excluded from hedge ineffectiveness. |
At September 30, 2011March 31, 2012 and December 31, 2010,2011, Exelon had $650 million and $100 million, respectively, of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $15$56 million and $14 million, respectively, which expire in 2015. Upon merger closing, $550 million of fixed-to-floating interest rate swaps previously at Constellation with a fair value of $44 million, as of March 12, 2012, were re-designated as fair value hedges. During the three and nine months ended September 30,March 31, 2012 and December 31, 2011, and 2010, there was nothe impact of loss on the results of operations as a result of ineffectiveness from fair value hedges.hedges was $1 million and $0 million, respectively.
At March 31, 2012, Exelon had $150 million of notional amounts related to interest rate swaps, with fair value assets of $5 million as of March 12, 2012, which were acquired as part of the merger with Constellation. These swaps are marked to market and expire in 2014. During the period from March 12 to March 31, 2012, the impact on the results of operations was immaterial.
Cash Flow Hedges. In connection with the DOE — guaranteed loan for the Antelope Valley acquisition, as discussed in Note 78 — Debt and Credit Agreements, Generation entered into a floating-to-fixed interest rate swap with a notional amount of $485 million, which hedges approximately 75% of Generation’s future interest rate exposure associated with the financing. The swap was designated as a cash flow hedge. As such, the effective portion of the hedge will be recorded in other comprehensive income within Generation’s Consolidated Balance Sheets, with any ineffectiveness recorded in Generation’s Consolidated Statements of Operations and Comprehensive Income. Net gains (or losses) from settlement of the hedges, to the extent effective, will be amortized as an adjustment to the interest expense over the term of the DOE — guaranteed loan.
As Generation draws down on the loan, a portion of the cash flow hedge will be de-designated and the related gains or losses will be reflected in earnings through the remaining term of the hedge.earnings. In order to mitigate this earnings impact, a series of offsetting hedge transactions will be executed as Generation draws on the loan. At March 31, 2012, Generation’s mark-to-market non-current derivative liability relating to the interest rate swap in connection with the loan agreement to fund Antelope Valley as discussed above was immaterial.
As a result of the receipt of the Antelope Valley loan advance on April 5, 2012, as described in Note 8 — Debt and Credit Agreements, Generation entered into a fixed-to-floating interest rate swap with a notional amount of $52 million, 75% of the loan advance amount to offset a portion of the original interest rate hedge, which is de-designated as a cash flow hedge. The remaining cash flow hedge has a notional amount of $433 million.
During the third quarter of 2011, a subsidiary of Constellation entered into forward starting interest rate swaps to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance a solar
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
project. The swaps have a total notional amount of $31 million as of March 31, 2012 and expire in 2027. Upon the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At March 31, 2012, the subsidiary had a $3 million non-current derivative liability related to these swaps.
During the three months ended March 31, 2012 and 2011, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial.
Fair Value Measurement (Exelon, Generation, ComEd, PECO and PECO)BGE)
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2011:March 31, 2012:
Generation | ComEd | PECO | Other | Exelon | Generation | ComEd | 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 | Economic Hedges(a) | Proprietary Trading | Collateral and Netting(b) | Subtotal (c) | Economic Hedges (a)(d) | Intercompany Eliminations (a) | Total Derivatives | |||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 287 | $ | 814 | $ | 164 | $ | (787 | ) | $ | 478 | $ | — | $ | — | $ | — | $ | — | $ | 478 | $ | 6,707 | $ | 7,904 | $ | (13,141 | ) | $ | 1,470 | $ | — | $ | — | $ | 1,470 | ||||||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 417 | — | — | — | 417 | — | — | — | (417 | ) | — | 590 | — | — | 590 | — | (590 | ) | — | |||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 126 | 395 | 53 | (289 | ) | 285 | — | — | 15 | — | 300 | 3,184 | 2,083 | (3,976 | ) | 1,291 | — | — | 1,291 | |||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 247 | — | — | — | 247 | — | — | — | (247 | ) | — | 92 | — | — | 92 | — | (92 | ) | — | |||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,077 | $ | 1,209 | $ | 217 | $ | (1,076 | ) | $ | 1,427 | $ | — | $ | — | $ | 15 | $ | (664 | ) | $ | 778 | $ | 10,573 | $ | 9,987 | $ | (17,117 | ) | $ | 3,443 | $ | — | $ | (682 | ) | $ | 2,761 | ||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (64 | ) | $ | (514 | ) | $ | (141 | ) | $ | 670 | $ | (49 | ) | $ | (2 | ) | $ | (1 | ) | $ | — | $ | — | $ | (52 | ) | $ | (6,203 | ) | $ | (7,939 | ) | $ | 13,072 | $ | (1,070 | ) | $ | (16 | ) | $ | — | $ | (1,086 | ) | ||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (415 | ) | (2 | ) | — | 417 | — | — | — | — | — | (590 | ) | 590 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (77 | ) | (154 | ) | (46 | ) | 259 | (18 | ) | (48 | ) | — | — | — | (66 | ) | (2,291 | ) | (2,028 | ) | 3,807 | (512 | ) | (125 | ) | — | (637 | ) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (247 | ) | — | — | 247 | — | — | — | — | — | (92 | ) | 92 | — | |||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (141 | ) | (668 | ) | (187 | ) | 929 | (67 | ) | (712 | ) | (3 | ) | — | 664 | (118 | ) | $ | (8,494 | ) | $ | (9,967 | ) | $ | 16,879 | $ | (1,582 | ) | $ | (823 | ) | $ | 682 | $ | (1,723 | ) | ||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 936 | $ | 541 | $ | 30 | $ | (147 | ) | $ | 1,360 | $ | (712 | ) | $ | (3 | ) | $ | 15 | $ | — | $ | 660 | $ | 2,079 | $ | 20 | $ | (238 | ) | $ | 1,861 | $ | (823 | ) | $ | — | $ | 1,038 | |||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
(c) | Current and noncurrent assets are shown net of collateral of |
(d) |
|
Includes current and noncurrent liabilities 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)
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2010:2011:
Generation | ComEd | PECO | Other | Exelon | Generation | ComEd | 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 | Cash Flow Hedges (a) | Economic Hedges | Proprietary Trading | Collateral and Netting(b) | Subtotal (c) | Economic Hedges (a)(d) | Economic Hedges | Intercompany Eliminations (a) | Total Derivatives | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 532 | $ | 1,203 | $ | 225 | $ | (1,473 | ) | $ | 487 | $ | — | $ | — | $ | — | $ | — | $ | 487 | $ | 438 | $ | 1,195 | $ | 217 | $ | (1,418 | ) | $ | 432 | $ | — | $ | — | $ | — | $ | 432 | ||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (current assets) | 455 | — | — | — | 455 | — | — | — | (455 | ) | — | 503 | — | — | — | 503 | — | — | (503 | ) | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 204 | 547 | 56 | (416 | ) | 391 | 4 | — | 14 | — | 409 | 419 | 582 | 71 | (437 | ) | 635 | — | 15 | — | 650 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets with affiliate (noncurrent assets) | 525 | — | — | — | 525 | — | — | — | (525 | ) | — | 191 | — | — | — | 191 | — | — | (191 | ) | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 1,716 | $ | 1,750 | $ | 281 | $ | (1,889 | ) | $ | 1,858 | $ | 4 | $ | — | $ | 14 | $ | (980 | ) | $ | 896 | $ | 1,551 | $ | 1,777 | $ | 288 | $ | (1,855 | ) | $ | 1,761 | $ | — | $ | 15 | $ | (694 | ) | $ | 1,082 | ||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (current liabilities) | $ | (21 | ) | $ | (551 | ) | $ | (200 | ) | $ | 738 | $ | (34 | ) | $ | — | $ | (4 | ) | $ | — | $ | — | $ | (38 | ) | $ | (9 | ) | $ | (965 | ) | $ | (194 | ) | $ | 1,065 | $ | (103 | ) | $ | (9 | ) | $ | — | $ | — | $ | (112 | ) | ||||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (current liabilities) | — | — | — | — | — | (450 | ) | (5 | ) | — | 455 | — | — | — | — | — | — | (503 | ) | — | 503 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (24 | ) | (143 | ) | (54 | ) | 200 | (21 | ) | — | — | — | — | (21 | ) | (4 | ) | (186 | ) | (70 | ) | 250 | (10 | ) | (97 | ) | — | — | (107 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liability with affiliate (noncurrent liabilities) | — | — | — | — | — | (525 | ) | — | — | 525 | — | — | — | — | — | — | (191 | ) | — | 191 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total mark-to-market derivative liabilities | (45 | ) | (694 | ) | (254 | ) | 938 | (55 | ) | (975 | ) | (9 | ) | — | 980 | (59 | ) | $ | (13 | ) | $ | (1,151 | ) | $ | (264 | ) | $ | 1,315 | $ | (113 | ) | $ | (800 | ) | $ | — | $ | 694 | $ | (219 | ) | |||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 1,671 | $ | 1,056 | $ | 27 | $ | (951 | ) | $ | 1,803 | $ | (971 | ) | $ | (9 | ) | $ | 14 | $ | — | $ | 837 | $ | 1,538 | $ | 626 | $ | 24 | $ | (540 | ) | $ | 1,648 | $ | (800 | ) | $ | 15 | $ | — | $ | 863 | |||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(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. |
(c) | Current and noncurrent assets are shown net of collateral of |
(d) | Includes current |
|
Cash Flow Hedges (Exelon Generation and ComEd)Generation). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At September 30, 2011,As discussed previously, effective prior to the merger with Constellation, Generation had net unrealized pre-tax gains on effectivede-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain probable, the fair value of $ 944 million being deferred within accumulated OCI, including $662 million related to the financial swap with ComEd. Amounts recordedeffective portion of these cash flow hedges was frozen in accumulated OCI related to changes in energy commodity cash flow hedges areand will be 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation’s Consolidated Statementsoccurs, or becomes probable of Operations, depending on the commodities involvednot occurring. Generation began recording prospective changes in the hedged transaction. Based on market prices at September 30, 2011, approximately $645fair value of these instruments through current earnings from the date of de-designation. The net unrealized gains associated with the de-designated cash flow hedges prior to the merger was $1,928 million including $693 million related to the intercompany swap with ComEd. Approximately $1,270 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 $415$597 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 20112012 through 2013.2014.
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 September 30,March 31, 2012 and 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 nine months ended September 30,March 31, 2012 and 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 September 30, 2011 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at June 30, 2011 | $ | 688 | (a)(d) | $ | 209 | |||||
Effective portion of changes in fair value | (26 | )(b) | (26 | ) | ||||||
Reclassifications from accumulated OCI | Operating Revenue | (98 | )(c) | (45 | ) | |||||
Ineffective portion recognized in income | Purchased Power | 7 | 7 | |||||||
|
|
|
| |||||||
Accumulated OCI derivative gain at September 30, 2011 | $ | 571 | (a)(d) | $ | 145 | |||||
|
|
|
|
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||
Generation | Exelon | |||||||||||
Three Months Ended March 31, 2012 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||
Accumulated OCI derivative gain at December 31, 2011 | $ | 925 | (a)(c) | $ | 488 | |||||||
Effective portion of changes in fair value | 432 | (e) | 317 | (d) | ||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | (194 | )(b) | (105 | ) | |||||||
Ineffective portion recognized in income | Operating Revenues | 3 | 3 | |||||||||
|
|
|
| |||||||||
Accumulated OCI derivative gain at March 31, 2012 | $ | 1,166 | (a)(c) | $ | 703 | |||||||
|
|
|
|
(a) | Includes |
|
|
|
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 | |||||||||
Nine Months Ended September 30, 2011 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at December 31, 2010 | $ | 1,011 | (a)(d) | $ | 400 | |||||
Effective portion of changes in fair value | (69 | )(b) | (73 | ) | ||||||
Reclassifications from accumulated OCI | Operating Revenue | (373 | )(c) | (184 | ) | |||||
Ineffective portion recognized in income | Purchased Power | 2 | 2 | |||||||
|
|
|
| |||||||
Accumulated OCI derivative gain at September 30, 2011 | $ | 571 | (a)(d) | $ | 145 | |||||
|
|
|
|
|
(b) | Includes |
|
Excludes |
(d) | Includes $12 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks. |
(e) | Includes $88 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 period ended March 9, 2012. |
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||
Generation | Exelon | |||||||||
Three Months Ended September 30, 2010 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at June 30, 2010 | $ | 1,158 | (a) | $ | 525 | |||||
Effective portion of changes in fair value | 401 | (b) | 283 | (e) | ||||||
Reclassifications from accumulated OCI | Operating Revenue | (104 | )(c) | (59 | )(f) | |||||
Ineffective portion recognized in income | Purchased Power | (2 | ) | (2 | ) | |||||
|
|
|
| |||||||
Accumulated OCI derivative gain at September 30, 2010 | $ | 1,453 | (a)(d) | $ | 747 | |||||
|
|
|
|
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||
Generation | Exelon | |||||||||||
Three Months Ended March 31, 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 | 63 | (b) | 18 | |||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | (132 | )(c) | (63 | ) | |||||||
Ineffective portion recognized in income | Purchased Power | (1 | ) | (1 | ) | |||||||
|
|
|
| |||||||||
Accumulated OCI derivative gain at March 31, 2011 | $ | 941 | (a)(d) | $ | 354 | |||||||
|
|
|
|
(a) | Includes |
(b) | Includes |
(c) | Includes |
|
|
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 | |||||||||
Nine Months Ended September 30, 2010 | Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||
Accumulated OCI derivative gain at December 31, 2009 | $ | 1,152 | (a) | $ | 551 | |||||
Effective portion of changes in fair value | 736 | (b) | 489 | (e) | ||||||
Reclassifications from accumulated OCI to net income | Operating Revenue | (433 | )(c) | (291 | )(f) | |||||
Ineffective portion recognized in income | Purchased Power | (2 | ) | (2 | ) | |||||
|
|
|
| |||||||
Accumulated OCI derivative gain at September 30, 2010 | $ | 1,453 | (a)(d) | $ | 747 | |||||
|
|
|
|
|
|
|
(d) | Excludes $2 million of gains, net of taxes, related to interest rate swaps |
|
|
During the three and nine months ended September 30,March 31, 2012 and 2011, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $162$320 million and a $617$218 million pre-tax gain, respectively, and a $171 million and $715 million pre-tax gain for the three and nine months ended September 30, 2010, respectively. Given that the cash flow hedges had primarily consistconsisted of forward power sales and power swaps and dodid not include gas options or sales, the ineffectiveness of Generation’s cash flow hedges iswas primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. This price difference iswas 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 decreases of $12$5 million and increases of $3$2 million through the date of de-designation in March of 2012 and for the three months ended September 30,March 31, 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 nine months ended September 30, 2011 and 2010, cash flow hedge ineffectiveness decreased by $4 million and increased by $3 million, respectively, primarily due to changes in market prices during the period, none of which was related to Generation’s financial swap contract with ComEdPECO or Generation’s block contracts with PECO. At September 30, 2011 and 2010, cashBGE. Cash flow hedge ineffectiveness resulted in a decrease of $3 million and an increase of $3 million, respectively, related to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.losses at March 31, 2011.
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 $173 million and a $105 million pre-tax gain for the three
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 $74 million and a $305 million pre-tax gain for the three and nine months ended September 30,March 31, 2012 and 2011, respectively, and a $102 million and a $485 million pre-tax gain for the three and nine months ended September 30, 2010, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were decreases of $12$5 million and increases of $3$2 million pre-taxthrough the date of de-designation in March of 2012 and for the three months ended September 30,March 31, 2011, and 2010, respectively, and decreases of $4 million and increases of $3 million for the nine months ended September 30, 2011 and 2010, respectively. At September 30, 2011 and 2010, cashCash flow hedge ineffectiveness resulted in a decrease of $3 million and an increase of $3 million, respectively, related to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.losses at March 31, 2011.
Other DerivativesEconomic Hedges (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 physical forward sales.sales and purchases. For the three and nine months ended September 30,March 31, 2012 and 2011, and 2010, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fueloperating revenues or purchased power and purchased powerfuel 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 | Generation | Intercompany Eliminations | Exelon | |||||||||||||||||||||||||||||
Three Months Ended September 30, 2011 | Purchased Power | Fuel | Total | |||||||||||||||||||||||||||||
Three Months Ended March 31, 2012 | Operating Revenues | Purchased Power and Fuel | Total | Operating Revenues(a) | Total | |||||||||||||||||||||||||||
Change in fair value | $ | (8 | ) | $ | 30 | $ | 22 | $ | 138 | $ | (40 | ) | $ | 98 | $ | 11 | $ | 109 | ||||||||||||||
Reclassification to realized at settlement | (51 | ) | (50 | ) | (101 | ) | (60 | ) | 27 | (33 | ) | — | (33 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Net mark-to-market (losses) | $ | (59 | ) | $ | (20 | ) | $ | (79 | ) | |||||||||||||||||||||||
Net mark-to-market gains (losses) | $ | 78 | $ | (13 | ) | $ | 65 | $ | 11 | $ | 76 | |||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Exelon and Generation | Exelon and Generation | |||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2011 | Purchased Power | Fuel | Total | |||||||||||||||||||||||||||||
Three Months Ended March 31, 2011 (As Reported) | Operating Revenues | Purchased Power and Fuel | Total | |||||||||||||||||||||||||||||
Change in fair value | $ | (29 | ) | $ | 42 | $ | 13 | $ | — | $ | (3 | ) | $ | (3 | ) | |||||||||||||||||
Reclassification to realized at settlement | (227 | ) | (145 | ) | (372 | ) | — | (145 | ) | (145 | ) | |||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Net mark-to-market (losses) | $ | (256 | ) | $ | (103 | ) | $ | (359 | ) | |||||||||||||||||||||||
Net mark-to-market gains (losses)(b) | $ | — | $ | (148 | ) | $ | (148 | ) | ||||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Exelon and Generation | Exelon and Generation | |||||||||||||||||||||||||||||||
Three Months Ended September 30, 2010 | Purchased Power | Fuel | Total | |||||||||||||||||||||||||||||
Operating Revenues | Purchased Power and Fuel | Total | ||||||||||||||||||||||||||||||
Three Months Ended March 31, 2011 | ||||||||||||||||||||||||||||||||
(Pro Forma) | ||||||||||||||||||||||||||||||||
Change in fair value | $ | 161 | $ | 55 | $ | 216 | $ | 1 | $ | (4 | ) | $ | (3 | ) | ||||||||||||||||||
Reclassification to realized at settlement | (57 | ) | 1 | (56 | ) | (132 | ) | (13 | ) | (145 | ) | |||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Net mark-to-market gains | $ | 104 | $ | 56 | $ | 160 | ||||||||||||||||||||||||||
Net mark-to-market gains (losses)(b) | $ | (131 | ) | $ | (17 | ) | $ | (148 | ) | |||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Exelon and Generation | ||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2010 | Purchased Power | Fuel | Total | |||||||||||||||||||||||||||||
Change in fair value | $ | 343 | $ | 129 | $ | 472 | ||||||||||||||||||||||||||
Reclassification to realized at settlement | (204 | ) | 2 | (202 | ) | |||||||||||||||||||||||||||
|
|
| ||||||||||||||||||||||||||||||
Net mark-to-market gains | $ | 139 | $ | 131 | $ | 270 | ||||||||||||||||||||||||||
|
|
|
(a) | Prior to the merger, the five year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value are recorded to operating revenues and eliminated in consolidation. |
(b) | Exelon and Generation have historically presented mark-to-market gains and losses within purchased power expense for all non-trading, energy-related derivatives that were not accounted for as cash flow hedges. In 2011, Exelon and Generation classified the mark-to-market gains and losses for contracts, where the underlying hedged transaction was an expected sale to hedge power, to operating revenues. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Proprietary Trading Activities (Exelon and Generation). For the three and nine months ended September 30,March 31, 2012 and 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 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 September 30, | Nine Months Ended September 30, | Location on Income Statement | Three Months Ended March 31, | ||||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2012 | 2011 | |||||||||||||||||||||||||||
Change in fair value | Operating Revenue | $ | 2 | $ | (1 | ) | $ | 22 | $ | 25 | Operating Revenues | $ | 2 | $ | 4 | |||||||||||||||||
Reclassification to realized at settlement | Operating Revenue | (6 | ) | (5 | ) | (19 | ) | (17 | ) | Operating Revenues | 1 | (6 | ) | |||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Net mark-to-market gains (losses) | Operating Revenue | $ | (4 | ) | $ | (6 | ) | $ | 3 | $ | 8 | Operating Revenues | $ | 3 | $ | (2 | ) | |||||||||||||||
|
|
|
|
|
|
Credit Risk (Exelon, Generation, ComEd, PECO and PECO)BGE)
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 September 30, 2011.March 31, 2012. 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, ICE and ICENodal commodity exchanges, further discussed in Item 3 — Quantitative and Qualitative Disclosures About Market Risk.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, PECO and PECOBGE of $57$76 million, $46 million and $38$8 million, respectively.
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 | 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 | |||||||||||||||||||||||||||||||
Rating as of September 30, 2011 | ||||||||||||||||||||||||||||||||||||||||
Rating as of March 31, 2012 | 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 | $ | 968 | $ | 167 | $ | 801 | 2 | $ | 192 | |||||||||||||||||||||||||||||||
Non-investment grade | 10 | 3 | 7 | — | — | |||||||||||||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||||||||||
Internally rated — investment grade | 35 | 7 | 28 | — | — | 617 | 19 | 598 | 1 | 293 | ||||||||||||||||||||||||||||||
Internally rated — non-investment grade | 4 | 2 | 2 | — | — | 41 | 4 | 37 | — | — | ||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||
Total | $ | 1,017 | $ | 179 | $ | 838 | 2 | $ | 192 | $ | 3,555 | $ | 967 | $ | 2,588 | 1 | $ | 293 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
Net Credit Exposure by Type of Counterparty | As of September 30, 2011 | As of March 31, 2012 | ||||||
Financial institutions | $ | 368 | ||||||
Investor-owned utilities, marketers and power producers | 281 | $ | 1,206 | |||||
Energy cooperatives and municipalities | 152 | 798 | ||||||
Financial institutions | 488 | |||||||
Other | 37 | 96 | ||||||
|
| |||||||
Total | $ | 838 | $ | 2,588 | ||||
|
|
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 after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of September 30, 2011,March 31, 2012, 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 2010Exelon 2011 Form 10-K for further information.
PECO’s supplier master agreements that govern the terms of its DSP Programelectric supply procurement 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 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 September 30, 2011, PECO’sMarch 31, 2012, PECO had no net credit exposure to suppliers was immaterial.suppliers.
PECO is permitted to recover its costs of procuring electric supply 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 34 — 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; however, the natural gas asset managers have provided $14 million in parental guarantees related to these agreements. As of September 30, 2011,March 31, 2012, PECO had credit exposure of $9$3 million under its natural gas supply and asset management agreements with investment grade suppliers.
BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 6 of BGE’s 2011 Form 10-K for further information.
BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, 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, subject to an unsecured credit cap. 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 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. The seller’s credit exposure is calculated each business day. As of March 31, 2012, BGE had no net credit exposure to suppliers.
BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demand, which are not covered by the gas cost adjustment clause. At March 31, 2012, BGE had credit exposure of $8 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third party suppliers.
Collateral and Contingent-Related Features (Exelon, Generation, ComEd, PECO and PECO)BGE)
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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, ICE and ICE.Nodal Exchange (“the exchanges”). The NYMEX and ICE clearing housesexchanges act as the counterparty to each trade. Transactions on NYMEX and ICEthe exchanges must adhere to comprehensive collateral and margining requirements.
Generation’s interest rate swap 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.
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 ICEthe exchanges that are fully collateralized) was $662 million and $742 million asis detailed in the table below:
Credit-Risk Related Contingent Feature | March 31, 2012 | |||||||||||||||
Gross Fair Value of Derivative Contracts Containing | Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements(2) | Net Fair Value of Derivative Contracts Containing This Feature(3) | Amount of Held/ (Posted) Collateral(4) | Contingent Collateral Obligation for Downgrade to BB+ or Ba1(5) | ||||||||||||
$ 5,623 | $ | 4,397 | $ | 1,226 | $ | (948) | $ | 2,772 |
Credit-Risk Related Contingent Feature | December 31, 2011 | |||||||||||||||
Gross Fair Value of Derivative Contracts Containing | Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements(2) | Net Fair Value of Derivative Contracts Containing This Feature(3) | Amount of Held/ (Posted) Collateral(4) | Contingent Collateral Obligation for Downgrade to BB+ or Ba1(5) | ||||||||||||
$ 1,014 | $ | 928 | $ | 86 | $ | 631 | $ | 1,612 |
(1) | Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features that are not fully collateralized by posted cash collateral on an individual, contract-by-contract basis ignoring the effects of master netting agreements. |
(2) | Amount represents the offsetting fair value of in-the-money derivative contracts under legally-enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which Exelon could potentially be required to post collateral. |
(3) | Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. |
(4) | Amount includes cash collateral held of $215 million and letters of credit posted of ($1,164) million at March 31, 2012 and cash collateral held of $542 million and letters of credit held of $89 million at December 31, 2011. |
(5) | Amounts represent the additional collateral that Exelon Generation Company, LLC and Constellation Energy Commodities Group, Inc. could be required to post with counterparties, including both cash collateral and letters of credit, in the event of a credit downgrade to below investment grade after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. |
Generation’s interest rate swaps contain provisions that, in the event of September 30, 2011 and December 31, 2010, respectively. Asa merger, if Generation’s debt ratings were to materially weaken, it would be in violation of September 30, 2011 and December 31, 2010, Generation hadthese provisions, resulting in the contractual rightability of offsetthe counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of $607 million and $717 million, respectively, related to derivative instruments that are assets with the sameagreement could result in a settlement payment by Exelon or the counterparty under master netting agreements, resultingon any interest rate swap in a net liability position of $55 million and $25 million, respectively. If Generation had been downgradedposition. The settlement amount would be equal 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 $184 million or $948 million, respectively, as of September 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, netfair value of the contractual rightswap on the termination date. As of offset under master netting agreements and the applicationMarch 31, 2012, Generation’s interest rate swap was in an asset position, with a fair value of collateral. $51 million.
See Note 18 of the 2010Exelon 2011 Form 10-K for further information regarding the letters of credit supporting the cash collateral.
Generation entered into SFCs with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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. 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 September 30, 2011,March 31, 2012, 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, underUnder 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 September 30, 2011,March 31, 2012, ComEd held approximately $19 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 2010Exelon 2011 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 the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2011,March 31, 2012, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of September 30, 2011,March 31, 2012, PECO could have been required to post approximately $44$48 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.
BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.
BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of March 31, 2012, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of March 31, 2012, the amount that BGE would have been required to provide related to its natural gas procurement contracts is well within BGE’s current available credit facility capacity of $599 million.
Exelon’s interest rate swaps contain provisions that, in the event of a merger, require thatif Exelon’s debt maintain an investment grade credit rating from Moody’s or S&P. If Exelon’s debtratings were to fall below investment grade,materially weaken, 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 September 30, 2011,March 31, 2012, Exelon’s interest rate swap was in an asset position, with a fair value of $15$65 million.
Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)
As of September 30, 2011March 31, 2012 and December 31, 2010, $12011, $22 million and $2 million, respectively, of cash collateral received was not offset against net derivative positions, because it wasthey were not associated with energy-related derivatives.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
7.8. Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and PECO)BGE)
Short-Term Borrowings
Exelon, ComEd and ComEdBGE 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. Exelon had bank lines of credit under committed credit facilities at March 31, 2012 for short-term financial needs, as follows:
Type of Credit Facility | Amount(a) | Expiration Dates | Capacity Type | |||||||
(In billions) | ||||||||||
Exelon Corporate | ||||||||||
Syndicated Revolver | $ | 2.00 | October 2013 to March 2016 | Letters of credit and cash | ||||||
Bilateral | 1.56 | September 2013 to December 2014 | Letters of credit and cash | |||||||
Generation | ||||||||||
Syndicated Revolver | 5.30 | March 2016 | Letters of credit and cash | |||||||
Bilateral | 0.30 | December 2015 and March 2016 | Letters of credit and cash | |||||||
ComEd | ||||||||||
Syndicated Revolver | 1.00 | March 2017 | Letters of credit and cash | |||||||
PECO | ||||||||||
Syndicated Revolver | 0.60 | March 2016 | Letters of credit and cash | |||||||
BGE | ||||||||||
Syndicated Revolver | 0.60 | March 2015 | Letters of credit and cash | |||||||
|
| |||||||||
Total | $ | 11.36 | ||||||||
|
|
(a) | Excludes $118 million of credit facility agreements arranged with minority and community banks at Generation, ComEd and PECO. These facilities, which expire in October 2012, are solely utilized to issue letters of credit. |
As of March 31, 2012, there were no borrowings under the Registrants’ credit facilities.
The Registrants had the following amounts of commercial paper borrowings outstanding as of March 31, 2012 and December 31, 2011:
Commercial Paper Borrowings | March 31, 2012 | December 31, 2011 | ||||||
Exelon Corporate | $ | — | $ | 161 | ||||
Generation | — | — | ||||||
ComEd | 302 | — | ||||||
PECO | — | — | ||||||
BGE | — | — |
ComEd Credit Facility
On March 28, 2012, ComEd replaced its unsecured revolving credit facility with a new facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement has an initial term expiring on March 28, 2017 and ComEd may request up to two, one-year extensions of that term. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. ComEd incurred $3 million in costs related to the replacement of the credit facility. These costs included upfront arranger fees and filing costs, which will be amortized to interest expense over the term of the credit facility.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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. 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 toBorrowings under 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 September 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, ComEdagreement 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 September 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,rate, plus an adder based upon ComEd’s credit rating. At September 30, 2011,The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreement requires ComEd to pay a facility fee based upon the aggregate commitments under the agreement. The maximum facility fee is 35 basis points. The fee varies depending upon ComEd’s adder was 87.5credit rating. As of March 31, 2012, ComEd adders were 27.5 basis points and 127.5 basis points for prime basedrate and LIBOR-based rate borrowings, and 187.5 basis points for LIBOR-based borrowings.respectively.
Generation, ComEd and PECO had $30 million, $32 million and $32 million, respectively,Exelon Credit Facilities
In connection with the Upstream Merger, Exelon assumed all of additionalConstellation’s obligations under its three-year, unsecured revolving credit facility agreements with minority(the “Constellation Credit Agreement”). Effective as of the Initial Merger, the Constellation Credit Agreement was amended and community banks located primarily within ComEd’srestated to (1) permit Exelon and PECO’s service territories. These facilities expired on October 21, 2011Constellation to consummate the Upstream Merger and were solely utilizedthe restructuring transaction, (2) reduce the aggregate commitments under the Constellation Credit Agreement from $2.5 billion to issue letters$1.5 billion, and (3) conform some of credit. Asthe representations, warranties, covenants and events of September 30, 2011, letters of credit issued under these agreements totaled $25 million, $21 million and $20 million for Generation, ComEd and PECO, respectively.
On October 21, 2011, Generation, ComEd and PECO replaced their expiring minority and community bank credit facility agreements with new minority and community bank credit facility agreementsdefault in the amountsConstellation Credit Agreement with representations, warranties, covenants and events of $50 million, $34 milliondefault in the Exelon credit agreement, dated as of March 23, 2011, as amended as of the Initial Merger. In connection with the Upstream Merger, Exelon also assumed Constellation’s obligations under four separate bilateral credit facilities and $34 million, respectively.
Additionally, on November 4, 2010, Generation entered into a bilateralcommodity-linked credit facility, which provides for an aggregate commitment of upwere also amended to $500 million. The effectiveness and full availabilityconform with the Constellation Credit Agreement effective as of the credit facilityInitial Merger. Effective as of the Initial Merger, the Exelon Credit Agreement and the Exelon Generation Credit Agreement were subjectamended and restated pursuant to various conditions. On February 22, 2011, Generation satisfied all conditionsan amendment to conform some of the representations, warranties and covenants with provisions of the Constellation Credit Agreement, as amended effective as of the Initial Merger. See Note 3 — Merger and Acquisitions for further description of the merger transaction.
Long-Term Debt
In connection with the Upstream Merger, Exelon (parent company) assumed the following series of debt obligations originally issued by Constellation under either its 1999 Indenture, Second Supplemental Indenture to the effectiveness2006 Indenture, or First Supplemental Indenture to 2008 Indenture:
$700 million aggregate principal amount of 7.60% Fixed-Rate Notes due 2032, all of which was outstanding as of March 31, 2012;
$550 million aggregate principal amount of 4.55% Fixed-Rate Notes due 2015, all of which was outstanding as of March 31, 2012;
$450 million aggregate principal amount of 8.625% Series A Junior Subordinated Debentures due 2063, all of which was outstanding as of March 31, 2012; and availability
$550 million aggregate principal amount of credit5.15% Notes due 2020, all of which was outstanding as of March 31, 2012.
In connection with the debt obligations assumed by Exelon as part of the merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the external obligations held by Exelon, resulting in intercompany notes payable at Generation and an intercompany notes receivable at Exelon Corporate. Under the intercompany loan agreements, interest and principal repayment by the Generation subsidiaries align with the payment of the interest and principal to third parties 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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.
Exelon, Generation, ComEd and PECO had the following amounts of commercial paper borrowings outstanding at September 30, 2011 and December 31, 2010:
Commercial Paper Borrowings | September 30, 2011 | December 31, 2010 | ||||||
Exelon Corporate | $ | 389 | $ | — | ||||
Generation | 73 | (a) | — | |||||
ComEd | — | — | ||||||
PECO | — | — |
|
As of September 30, 2011, there were no borrowings under the Registrants’ credit facilities.assumed debt obligations.
Issuance of Long-Term Debt
During the ninethree months ended September 30, 2011, the followingMarch 31, 2012, there were no issuances of long-term debt was issued:debt.
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. | |||||||||
ComEd | First Mortgage Bonds(a) | 1.950 | % | September 1, 2016 | $ | 250 | To be used to refinance the outstanding principal amount of three series of variable rate tax-exempt bonds, to refinance the outstanding principal of First Mortgage 5.40% Bonds due December 15, 2011 and for general corporate purposes. | |||||||||
ComEd | First Mortgage Bonds(a) | 3.400 | % | September 1, 2021 | $ | 350 | To be used to refinance the outstanding principal amount of three series of variable rate tax-exempt bonds, to refinance the outstanding principal of First Mortgage 5.40% Bonds due December 15, 2011 and for general corporate purposes. |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
During the ninethree months ended September 30, 2010,March 31, 2011, the following long-term debt was issued:
Company | Type | Interest Rate | Maturity | Amount(a) | Use of Proceeds | |||||||||||
Generation | Senior Notes | 4.00 | % | October 1, 2020 | $ | 550 | Used to finance the acquisition of John Deere Renewables and for general corporate purposes. | |||||||||
Generation | Senior Notes | 5.75 | % | October 1, 2041 | 350 | Used to finance the acquisition of John Deere Renewables and for general corporate purposes. | ||||||||||
ComEd | First Mortgage Bonds | 4.00 | % | August 1, 2020 | 500 | Used to refinance First Mortgage Bonds, Series 102, which matured on August 15, 2010 and for other general corporate purposes. |
|
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 January 2011 contribution for Exelon-sponsored pension plans in which ComEd participates and for other general corporate purposes. |
Retirement of Long-Term Debt
During the ninethree months ended September 30,March 31, 2012, the following long-term debt was retired:
Company | Type | Interest Rate | Maturity | Amount | ||||||||||||
ComEd | First Mortgage Bond Series 98 | 6.15 | % | March 15, 2012 | $ | 450 |
During the three months ended March 31, 2011, the following long-term debt was retired:
Company | Type | Interest Rate | Maturity | Amount | ||||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | $ | 2 | ||||||||
ComEd | Sinking fund debentures | 4.75 | % | December 1, 2011 | 1 |
On October 12, 2011, ComEd retired $91 million of variable rate tax-exempt bonds due March 1, 2017, $50 million of variable rate tax-exempt bonds due March 1, 2020 and $50 million of variable rate tax exempt bonds due May 1, 2021.
During the nine months ended September 30, 2010, the following long-term debt was retired:
Company | Type | Interest Rate | Maturity | Amount | Type | Interest Rate | Maturity | Amount | ||||||||||||||||||||||
Exelon | 2005 Senior Notes | 4.45 | % | June 15, 2010 | $ | 400 | ||||||||||||||||||||||||
Generation | Kennett Square Capital Lease | 7.83 | % | September 20, 2020 | 1 | 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 | ||||||||||||||||||||||||||
ComEd | Sinking fund debentures | 4.75 | % | December 1, 2011 | 1 | |||||||||||||||||||||||||
ComEd | First Mortgage Bonds | 4.74 | % | August 15, 2010 | 212 | |||||||||||||||||||||||||
PECO | PETT Transition Bonds | 6.52 | % | September 1, 2010 | 806 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Variable Rate Debt
As of September 30, 2011, ComEd’s variable rate tax-exempt debt was supported by letters of credit, which were released and cancelled following the retirement of that debt in October 2011 as discussed above. ComEd has classified amounts outstanding under these debt agreements as short-term debt based on the retirement of the debt in October 2011.
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 September 30, 2011March 31, 2012 and December 31, 2010,2011, the financial institution’s undivided interest in Exelon’s and PECO’s gross customer accounts receivable was equivalent to $351$348 million and $346$329 million, respectively, which isrepresents the financial institution’s interest in PECO’s eligible receivables as calculated under the terms of the agreement. The agreement requires PECO to maintain eligible receivables at least equivalent to the financial institution’s undivided interest. Effective April 30, 2012, PECO and the financial institution entered into an amendment to the agreement, which modifies certain eligibility criteria, which will increase the amount of PECO’s receivables that will be considered eligible receivables under the agreement for purposes of satisfying this requirement. 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. On September 2, 2011, PECO extended this agreement, which now terminates on August 31, 2012.2012 unless extended in accordance with its terms. As of September 30, 2011,March 31, 2012, PECO was in compliance with the requirements of the agreement. In the event the agreement is not further extended, PECO has sufficient short-term liquidity and may seek alternate financing.
Antelope Valley Project Development Debt Agreement
TheOn September 28, 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. Advances under the loan are contingent on the satisfaction of various conditions. The purchase agreement contains a provision that First Solar, Inc. will repurchase Antelope Valley if initial funding of the loan does not occur by the end of 2011. The project is expected to be completed at the end of 2013. The loan will mature on January 5, 2037. Interest rates on the loan will be fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. In connection with this agreement, Generation entered into a floating-for-fixed interest rate swap with a notional amount of $485 million to mitigate interest rate risk associated with the financing. See Note 6 — Derivative Financial Instruments for additional information on the interest rate swap. In addition, Generation has issued letters of credit to support its equity investment in the project. As of September 30, 2011, Generation had $6 million in letters of credit outstanding related to the project. Generation expects to issue additional letters of credit to support their equity investment in the project prior to the first loan advance to Antelope Valley. The letters of credit balance is expected to decline over time as scheduled equity contributions for the project are made.floating-to-fixed
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
interest rate swap with a notional amount of $485 million to mitigate interest rate risk associated with the financing prior to the advances. On April 5, 2012, Antelope Valley received the first DOE-guaranteed loan advance of $69 million and terminated the put option that Generation had on the Antelope Valley project. As a result, Generation entered into a fixed-to-floating interest rate swap with a notional amount of $52 million, 75% of the first loan advance amount to offset a portion of the original interest rate hedge. See Note 7 — Derivative Financial Instruments for additional information on the interest rate swap.
In addition, Generation has issued letters of credit to support its equity investment in the project. As of March 31, 2012, Generation had $689 million in letters of credit outstanding related to the project The letters of credit balance is expected to decline over time as scheduled equity contributions for the project are made.
8.9. Income Taxes (Exelon, Generation, ComEd, PECO and PECO)BGE)
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 September 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||||||||||||||||||||||
For the Three Months Ended March 31, 2012 | Exelon(a) | Generation(a) | ComEd | PECO | BGE(b) | |||||||||||||||||||||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||||||||||||
Increase (decrease) due to: | ||||||||||||||||||||||||||||||||||||
State income taxes, net of Federal income tax benefit | 4.8 | 5.5 | 0.8 | 2.9 | (27.4 | ) | 1.2 | 5.9 | 3.4 | 4.4 | ||||||||||||||||||||||||||
Qualified nuclear decommissioning trust fund income | (6.4 | ) | (10.2 | ) | — | — | 16.0 | 14.7 | — | — | — | |||||||||||||||||||||||||
Domestic production activities deduction | 1.0 | 1.7 | — | — | (1.2 | ) | (1.2 | ) | — | — | — | |||||||||||||||||||||||||
Tax exempt income | (0.1 | ) | (0.2 | ) | — | — | (0.4 | ) | (0.4 | ) | — | — | — | |||||||||||||||||||||||
Health Care Reform Acts(a) | — | — | 0.3 | — | ||||||||||||||||||||||||||||||||
Health Care Reform Legislation | 0.2 | — | 0.4 | — | — | |||||||||||||||||||||||||||||||
Amortization of investment tax credit | (0.8 | ) | (0.5 | ) | (0.3 | ) | (0.3 | ) | 0.9 | |||||||||||||||||||||||||||
Plant basis differences | (3.0 | ) | — | — | (3.5 | ) | 2.7 | |||||||||||||||||||||||||||||
Production tax credits | (0.5 | ) | (3.1 | ) | — | — | — | |||||||||||||||||||||||||||||
Fines & Penalties | 13.3 | 11.9 | — | — | — | |||||||||||||||||||||||||||||||
Merger Expenses | 13.2 | — | — | — | (8.5 | ) | ||||||||||||||||||||||||||||||
Other | (0.3 | ) | 0.5 | 0.2 | (0.1 | ) | 0.3 | |||||||||||||||||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||
Effective income tax rate | 44.1 | % | 58.1 | % | 41.2 | % | 34.5 | % | 34.8 | % | ||||||||||||||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||
For the Three Months Ended March 31, 2011 | Exelon | Generation | ComEd | PECO | BGE(b) | |||||||||||||||||||||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||||||||||||||||||||
Increase (decrease) due to: | ||||||||||||||||||||||||||||||||||||
State income taxes, net of Federal income tax benefit | 5.5 | 6.1 | 7.3 | (3.9 | ) | 4.6 | ||||||||||||||||||||||||||||||
Qualified nuclear decommissioning trust fund income | 2.3 | 3.2 | — | — | — | |||||||||||||||||||||||||||||||
Domestic production activities deduction | (0.9 | ) | (1.3 | ) | — | — | — | |||||||||||||||||||||||||||||
Tax exempt income | (0.1 | ) | (0.1 | ) | — | — | — | |||||||||||||||||||||||||||||
Health Care Reform Legislation | — | — | — | — | (1.9 | ) | ||||||||||||||||||||||||||||||
Amortization of investment tax credit | (0.3 | ) | (0.2 | ) | (0.5 | ) | (0.3 | ) | (0.2 | ) | (0.2 | ) | (0.4 | ) | (0.3 | ) | (0.2 | ) | ||||||||||||||||||
Plant basis differences | (3.2 | ) | — | (0.7 | ) | (23.8 | ) | — | — | — | (0.2 | ) | (0.8 | ) | ||||||||||||||||||||||
Production tax credits | (1.1 | ) | (1.7 | ) | — | — | (0.9 | ) | (1.3 | ) | — | — | — | |||||||||||||||||||||||
Other | 0.1 | 0.3 | 0.4 | 0.1 | (0.7 | ) | (1.0 | ) | 0.1 | 0.2 | — | |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Effective income tax rate | 29.8 | % | 30.2 | % | 35.3 | % | 13.9 | % | 40.0 | % | 40.4 | % | 42.0 | % | 30.8 | % | 36.7 | % | ||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
For the Nine Months Ended September 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 | 4.1 | 4.9 | 3.4 | (0.4 | ) | |||||||||||||||||||||||||||||||
Qualified nuclear decommissioning trust fund income | (0.6 | ) | (0.8 | ) | — | — | ||||||||||||||||||||||||||||||
Domestic production activities deduction | (0.4 | ) | (0.6 | ) | — | — | ||||||||||||||||||||||||||||||
Tax exempt income | (0.1 | ) | (0.2 | ) | — | — | ||||||||||||||||||||||||||||||
Health Care Reform Acts(a) | — | — | (1.5 | ) | — | |||||||||||||||||||||||||||||||
Amortization of investment tax credit | (0.3 | ) | (0.2 | ) | (0.4 | ) | (0.3 | ) | ||||||||||||||||||||||||||||
Plant basis differences | (1.0 | ) | — | (0.4 | ) | (6.8 | ) | |||||||||||||||||||||||||||||
Production tax credits | (1.0 | ) | (1.4 | ) | — | — | ||||||||||||||||||||||||||||||
Other | (0.3 | ) | (0.9 | ) | 0.3 | — | ||||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||||||
Effective income tax rate | 35.4 | % | 35.8 | % | 36.4 | % | 27.5 | % | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||||||
For the Three Months Ended September 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 | 1.6 | 3.2 | 4.8 | (5.8 | ) | |||||||||||||||||||||||||||||||
Qualified nuclear decommissioning trust fund income | 4.1 | 5.4 | — | — | ||||||||||||||||||||||||||||||||
Domestic production activities deduction | (1.4 | ) | (1.7 | ) | — | — | ||||||||||||||||||||||||||||||
Tax exempt income | (0.1 | ) | (0.1 | ) | — | — | ||||||||||||||||||||||||||||||
Amortization of investment tax credit | (0.2 | ) | (0.1 | ) | (0.4 | ) | (0.4 | ) | ||||||||||||||||||||||||||||
Plant basis differences | — | — | (0.1 | ) | — | |||||||||||||||||||||||||||||||
Other | 0.5 | — | 0.2 | 0.6 | ||||||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||||||
Effective income tax rate | 39.5 | % | 41.7 | % | 39.5 | % | 29.4 | % | ||||||||||||||||||||||||||||
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
For the Nine Months Ended September 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 | 2.8 | 3.7 | 6.6 | (5.9 | ) | |||||||||||
Qualified nuclear decommissioning trust fund income | 1.3 | 1.7 | — | — | ||||||||||||
Domestic production activities deduction | (1.8 | ) | (2.4 | ) | — | — | ||||||||||
Tax exempt income | (0.1 | ) | (0.2 | ) | — | — | ||||||||||
Health Care Reform Acts(b) | 1.7 | 0.9 | 1.7 | 1.7 | ||||||||||||
Amortization of investment tax credit | (0.2 | ) | (0.2 | ) | (0.4 | ) | (0.4 | ) | ||||||||
Plant basis differences | — | — | (0.1 | ) | 0.1 | |||||||||||
Uncertain tax position remeasurement | — | (2.6 | ) | 11.5 | — | |||||||||||
Other | 0.1 | — | 0.2 | 0.2 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Effective income tax rate | 38.8 | % | 35.9 | % | 54.5 | % | 30.7 | % | ||||||||
|
|
|
|
|
|
|
|
(a) |
|
(b) |
|
(c) | Prior to the close of the |
Accounting for Uncertainty in Income Taxes
Exelon, Generation, ComEd, PECO, and PECOBGE have $836$1,040 million, $710$874 million, $70$69 million, $48 million, and $48$11 million, respectively, of unrecognized tax benefits as of September 30, 2011.March 31, 2012. Exelon’s, Generation’s, ComEd’s, PECO’s and PECO’sBGE’s uncertain tax positions have not significantly changed since December 31, 2010.2011. See Note 11 of the 2010Exelon 2011 Form 10-K and Note 10 of the 2011 Form 10-K for Constellation and BGE for further discussion of reasonably possible changes that could occur in unrecognized tax benefits during the next twelve months.
Other Income Tax Matters
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 a taking of their respective properties 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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.Inmillion. 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 2010 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
parties and is subject to the review of the Joint Committee on Taxation. 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. In the second quarter of 2012, IRS Appeals submitted the final terms, calculations, and definitive agreements to the Joint Committee on Taxation for its review.
Under the terms of the preliminary agreement, Exelon estimates that the IRS will assess tax and interest of approximately $300 million in 2012 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 $365 million between 2012 and 2014, including the refund resulting from the nuclear decommissioning trust fund special transfer tax deduction described below, of which $55 million and $335 million would be received by Generation and ComEd, respectively, and the remainder paid by Exelon.
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 September 30, 2011,March 31, 2012, 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
of a fully successful IRS challenge to Exelon’s like-kind exchange position could be as much as $850$840 million, of which $540$520 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 September 30, 2011,March 31, 2012, by as much as $250$240 million, net of tax, of which $190$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)COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
During 2008, Generation benefited from a provision(Dollars 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 that 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 confirmed 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. As of October 20, 2011, Exelon has received favorable rulings from the IRS on all of its ruling requests. Exelon recorded an interest and tax benefit of $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. In addition, during the third quarter, Exelon completed additional special transfers resulting in an additional interest benefit of $3 million, net of tax.millions, except per share data, unless otherwise noted)
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 $11 million and $4 million of additional tax relates to Exelon Corporate and Generation, respectively, and a $10 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 and the electric transmission and distribution property repairs deduction discussed below.
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
tax law and/or significant operational changes, such as the 2011 Illinois State Tax Rate Legislation discussed above. Due to the extent and naturemerger with Constellation. As a result of the operations conducted by Exelon and Generation in Illinois,merger, Exelon and Generation reevaluated their long-term state tax apportionment for Illinois and all other states where they have state income tax obligations.obligations, which include Illinois, Maryland and Pennsylvania, as well as other states. The total effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax charge during the first quarterasset of 2011 of $22 million and $11$72 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 inExelon. Of this, 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, Generation, ComEd and PECO)
On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. ComEd intends to adopt the safe harbor in the Revenue Procedure for the 2011 tax year. PECO adopted the safe harbor for the 2010 tax year. For the three and nine months ended September 30, 2011, the adoption of the safe harbor resulted in a $26 million reduction to income tax expense at PECO, while Generation incurred additional income tax expense in the amount of $23$116 million dueand $14 million (net of Federal taxes) was recorded for Exelon and Generation, respectively, for the three months ended March 31, 2012. Further, Exelon and Generation recorded deferred state tax liabilities of $44 million and $14 million (net of Federal taxes), respectively, as part of purchase accounting during the three months ended March 31, 2012.
Interest Expense on Income Taxes (BGE)
For the three months ended March 31, 2012, BGE recorded an adjustment to a decrease in its manufacturer’s deduction, which are reflected ininterest expense of approximately $5 million to reflect the effectiveimpacts of anticipated amendments of tax positions previously taken on prior-year consolidated income tax rate reconciliation above in the plant basis differences and domestic production activities deduction lines, respectively. For Exelon, the adoption had a minimal effect on consolidated earnings. In addition, the adoptionreturns. BGE has concluded this adjustment is not material to its results of the safe harbor will result in aoperations or cash tax benefit at Exelon, ComEd and PECO in the amount of approximately $300 million, $250 million and $95 million, respectively, partially offset by a cash tax detriment at Generation in the amount of $28 million.
See Note 3 — Regulatory Matters for discussion of the regulatory treatment prescribed in the 2010 electric distribution rate case settlement for PECO’s cash tax benefit resulting from the application of the method change to years prior to 2010.
Tax Sharing Agreement (Exelon, Generation, ComEd and PECO)
Generation, ComEd and PECO are all party to an agreement with Exelon and other subsidiaries of Exelon that providesflows for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition,three months ended March 31, 2012, or any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During the third quarter of 2011, Generation and PECO recorded an allocation of Federal benefits from Exelon under the Tax Sharing Agreement of $30 million and $18 million, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
prior period.
9.10. 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.
During the third quarter of 2011, Generation recorded a net increase in the ARO of $176 million primarily due to an increase in the estimated costs to decommission the Oyster Creek and Zion nuclear units resulting from the completion of updated decommissioning cost studies received in 2011 and an increase in the expected long-term escalation rates for energy, partially offset by decreases in long-term escalation rates for labor and other costs as compared to prior study periods. The increase in the Zion nuclear unit ARO resulted in $28 million of expense, which is included in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income, as the Zion nuclear unit is retired, and as such, is unable to record increases to the ARO through an ARC. Additionally, the Zion nuclear unit is not subject to a regulatory agreement that would provide for offset of the expense.
During the third quarter of 2010, Generation’s ARO decreased by $205 million, primarily reflecting the ZionSolutions’ assumption of decommissioning and other liabilities for Zion Station, offset in part by accretion and by increases for updates to estimated future cash flows across all of Generation’s units. Changes in estimated future cash flows increased the ARO by $452 million, including approximately $200 million associated with the accelerated timing of the Zion Station decommissioning. The remainder of the increase is the result of cost study estimate updates and the change in timing of general decommissioning activities at select sites in Generation’s nuclear fleet, including revisions to the timing and amount of SNF disposal; partially offset by the impacts of lower escalation rates. This change in the ARO resulted in an immaterial impact to Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 20102011 to September 30, 2011:March 31, 2012:
Exelon and Generation | ||||||||
Nuclear decommissioning ARO at December 31, 2010(a) | $ | 3,276 | ||||||
Nuclear decommissioning ARO at December 31, 2011(a) | $ | 3,680 | ||||||
Accretion expense | 155 | 55 | ||||||
Net increase due to changes in estimated cash flows | 176 | 80 | ||||||
Costs incurred to decommission retired plants | (3 | ) | (1 | ) | ||||
|
| |||||||
Nuclear decommissioning ARO at September 30, 2011(a) | $ | 3,604 | ||||||
Nuclear decommissioning ARO at March 31, 2012(a) | $ | 3,814 | ||||||
|
|
(a) | Includes $5 million as the current portion of the ARO at |
During the first quarter of 2012, Generation’s ARO increased by $134 million, primarily due to increases for accretion and a net increase of $80 million due to changes in estimated cash flows primarily related to increased costs resulting from an updated decommissioning cost study received for the Quad Cities generating station. The increase due to the changes in estimated cash flows had no impact to Exelon’s or Generation’s Consolidated Statements of Operations and Comprehensive Income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nuclear Decommissioning Trust Fund Investments
Generation will pay for its nuclear decommissioning obligations using trustNDT funds that have been established for this purpose. each generating station unit to satisfy Generation’s nuclear decommissioning obligations. NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
The NDT funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO currently collects funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections may continue through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 30, 2012, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of $24 million which, if approved by the PAPUC, will be effective January 1, 2013. This amount reflects a reduction from the current approved annual collections of $29 million. See Note 12 of the Exelon 2011 Form 10-K for information regarding amounts collected from PECO customers for decommissioning costs. See below for discussion of NRC minimum funding requirements.
At September 30, 2011March 31, 2012 and December 31, 2010,2011, Exelon and Generation had NDT fund investments totaling $6,226$6,927 million and $6,408$6,507 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2011March 31, 2012 and 2010:2011:
Exelon and Generation | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a) | $ | (363 | ) | $ | 324 | $ | (223 | ) | $ | 117 | ||||||
Non-Regulatory Agreement Units(b)(c) | (141 | ) | 107 | (88 | ) | 48 |
Three Months Ended | ||||||||
March 31, | ||||||||
2012 | 2011 | |||||||
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 247 | $ | 111 | ||||
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c) | 65 | 43 |
(a) | Net unrealized gains |
(b) | Excludes |
(c) |
|
Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in ExelonExelon’s and Generation’s Consolidated Statements of Operations.Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units, which are subject to regulatory accounting, are eliminated within Other, net in ExelonExelon’s and Generation’s Consolidated StatementsStatement of Operations.Operations and Comprehensive Income.
See Note 2 of the 2010Exelon 2011 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Zion Station DecommissioningDecommissioning. . On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC.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 2010Exelon 2011 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 and Bank of New York Mellon filed a motion to dismiss the complaint on September 13, 2011.
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 GenerationGeneration’s 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
decommissioning was replaced with a payable to ZionSolutions in GenerationGeneration’s 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 $64$66 million, which is included within the nuclear decommissioning ARO at September 30, 2011.March 31, 2012. 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 September 30, 2011,March 31, 2012, the carrying value of the Zion Station pledged assets and the payable to Zion Solutions was approximately $763$708 million and $720$660 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 September 30, 2011March 31, 2012 and December 31, 20102011 was $116$86 million and $127$128 million, respectively.
Securities Lending Program. Generation’s NDT funds participate in a securities lending program with the trustees of the funds. 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, which are adjusted daily, 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.
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 pools is approximately 18 months. The fair value of securities on loan was approximately $16 million and $51 million at September 30, 2011 and December 31, 2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $15 million at September 30, 2011 and $51 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.
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 10,31, 2011, Generation, in its NRC-required biennial decommissioning funding status report, provided data from which the NRC concluded that the amount of decommissioning funding as of December 31, 2010 for Limerick Unit 1 was less than the amount required by the NRC’s regulations. Generation notifiedperformed the calculations again in early 2012, which reflected that the amount of decommissioning funding as of December 31, 2011 for Limerick Unit 1 was less than the amount required by the NRC’s regulations. In February 2012, Generation obtained a parent guarantee in the amount of $115 million to cover the NRC minimum funding assurance requirements for Limerick Unit 1 and informed the NRC that it had remediatedaddressed 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 cancelled these parent guarantees on August 6, 2011. As the future values of trust funds change due to market conditions, the NRC minimum funding statusissues by obtaining the parent guarantee.
11. Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)
Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. Effective March 12, 2012, Exelon became the sponsor 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 PECOall of Constellation’s defined benefit pension and other postretirement benefit plans and defined contribution
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
customers for decommissioningsavings plans. As of that date, the former PECO nuclear plants,legacy Constellation pension and other postretirement benefits plans were remeasured using current assumptions including 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.
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.discount rate.
Defined Benefit Pension and Other Postretirement Benefits
During the first quarter of 2011,2012, Exelon received an updated valuation of its December 31, 2011 legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2011.2012. This valuation resulted in a decreasean increase to the pension obligations of $6 million and a decrease to other postretirement obligations of $28 million.$86 million and $25 million, respectively. Additionally, accumulated other comprehensive loss decreased by approximately $39$8 million (after tax) and regulatory assets increased by $31$98 million.
The following tables present the components of Exelon’s net periodic benefit costs for the three and nine months ended September 30, 2011March 31, 2012 and 2010.2011. The 20112012 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 8.00%.7.50% for all plans and discount rates of 4.74% and 4.27% for legacy Exelon and Constellation plans, respectively. The 20112012 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 7.08%.6.68% for funded plans, and a discount rate of 4.80% and 4.28% for legacy Exelon and Constellation plans, respectively. Legacy Constellation other postretirement plans are not funded. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.
Pension Benefits Three Months Ended September 30, | Other Postretirement Benefits Three Months Ended September 30, | |||||||||||||||||||||||||||||||
Pension Benefits Three Months Ended March 31, | Other Postretirement Benefits Three Months Ended March 31, | |||||||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2012 | 2011 | 2012 | 2011 | |||||||||||||||||||||||||
Service cost | $ | 53 | $ | 47 | $ | 36 | $ | 31 | $ | 61 | $ | 53 | $ | 37 | $ | 36 | ||||||||||||||||
Interest cost | 162 | 164 | 52 | 53 | 164 | 162 | 51 | 52 | ||||||||||||||||||||||||
Expected return on assets | (235 | ) | (200 | ) | (27 | ) | (27 | ) | (232 | ) | (235 | ) | (29 | ) | (28 | ) | ||||||||||||||||
Settlements | — | 4 | — | — | ||||||||||||||||||||||||||||
Amortization of: | ||||||||||||||||||||||||||||||||
Transition obligation | — | — | 2 | 3 | — | — | 3 | 2 | ||||||||||||||||||||||||
Prior service cost (benefit) | 4 | 4 | (10 | ) | (14 | ) | 4 | 4 | (3 | ) | (9 | ) | ||||||||||||||||||||
Actuarial loss | 83 | 64 | 16 | 18 | 106 | 83 | 19 | 16 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Net periodic benefit cost | $ | 67 | $ | 83 | $ | 69 | $ | 64 | $ | 103 | $ | 67 | $ | 78 | $ | 69 | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Pension Benefits Nine Months Ended September 30, | Other Postretirement Benefits Nine Months Ended September 30, | |||||||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||||
Service cost | $ | 159 | $ | 143 | $ | 107 | $ | 93 | ||||||||||||||||||||||||
Interest cost | 487 | 494 | 155 | 160 | ||||||||||||||||||||||||||||
Expected return on assets | (704 | ) | (600 | ) | (83 | ) | (81 | ) | ||||||||||||||||||||||||
Settlements | — | 4 | — | — | ||||||||||||||||||||||||||||
Amortization of: | ||||||||||||||||||||||||||||||||
Transition obligation | — | — | 7 | 7 | ||||||||||||||||||||||||||||
Prior service cost (benefit) | 11 | 11 | (29 | ) | (42 | ) | ||||||||||||||||||||||||||
Actuarial loss | 248 | 191 | 49 | 55 | ||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Net periodic benefit cost | $ | 201 | $ | 243 | $ | 206 | $ | 192 | ||||||||||||||||||||||||
|
|
|
|
The following amounts were included in capital additions and operating and maintenance expense during the three months ended March 31, 2012 and 2011, for Generation’s, ComEd’s, PECO’s, BGE’s and BSC’s allocated portion of the pension and postretirement benefit plans:
Three Months Ended March 31, | ||||||||
Pension and Other Postretirement Benefit Costs | 2012 | 2011 | ||||||
Generation | $ | 81 | $ | 62 | ||||
ComEd | 69 | 54 | ||||||
PECO | 13 | 8 | ||||||
BGE(a) | 16 | 11 | ||||||
BSC(b) | 14 | 12 |
(a) | BGE’s pension and postretirement benefit costs for the three months ended March 31, 2012 and 2011 include $12 million and $11 million, respectively, of costs incurred prior to the closing of Exelon’s merger with Constellation on March 12, 2012. These amounts are not included in Exelon’s net periodic benefit cost for the three months ended March 31, 2012 and 2011 shown in the first table of the Defined Benefit Pension and Other Postretirement Benefits section above. |
(b) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. |
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 nine months ended September 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 September 30, | Nine Months Ended September 30, | |||||||||||||||
Pension and Postretirement Benefit Costs | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Generation | $ | 64 | $ | 68 | $ | 187 | $ | 202 | ||||||||
ComEd | 53 | 55 | 160 | 161 | ||||||||||||
PECO | 8 | 11 | 24 | 35 | ||||||||||||
BSC(a) | 11 | 13 | 36 | 37 |
|
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. Exelon contributed $2.1 billionexpects to contribute $100 million 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 throughout 2011,2012, of which Generation, ComEd and PECO will contribute $5$59 million, $2$12 million, and $16 million, respectively. Legacy Constellation’s 2011 pension contributions included an acceleration of estimated calendar year 2012 contributions. Therefore, BGE does not anticipate any qualified pension contributions in 2012. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $61 million in 2012, of which Generation, ComEd, PECO and BGE will make payments of $9 million, $14 million, $1 million and $1 million, respectively.
Unlike the qualified pension plans, Exelon’s other postretirement plans are not subject to regulatory minimum contribution requirements. Management considersExelon’s management has historically considered several factors in determining the level of contributions to Exelon’sits other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery). In 2012, Exelon expects to contribute approximately $271 million to theanticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with the exception of those plans previously sponsored by Constellation and AmerGen, which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $321 million in the fourth quarter of 2011,2012, of which Generation, ComEd, PECO and PECOBGE expect to contribute $118$132 million, $105$116 million, $34 million and $28$17 million, respectively. This total excludes $4 million in 2012 other postretirement benefit plan contributions by BGE prior to the closing of Exelon’s merger with Constellation on March 12, 2012.
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 pensionhas developed and implemented an investment strategy in order to reducefor its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. As a resultExelon is likely to continue to gradually increase the liability hedging portfolio as the funded status 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.its plans improves. 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. Exelon currently has a target asset allocation of approximately 30% public equity investments, 50% fixed income investments and 20% alternative investments. The change in the overallThis investment strategy would tend to result in a 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 benefityears. Trust assets for Exelon’s other postretirement plans currently participateare managed in a securities lending program with the trustees of the plans’diversified 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%strategy that prioritizes maximizing liquidity and 105% of the market value of the borrowed securities forreturns while minimizing asset volatility.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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.
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 12 months. The fair value of securities on loan was approximately $15 million and $46 million at September 30, 2011 and December 31, 2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $16 million at September 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.
401(k)Defined Contribution Savings PlanPlans
The Registrants participate in avarious 401(k) defined contribution savings planplans that are sponsored by Exelon. The plan allowsplans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Exelon, Generation, ComEd and PECOAll Registrants match a percentage of the employee 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 nine months ended September 30, 2011March 31, 2012 and 2010:2011:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||
Savings Plan Matching Contributions | 2011 | 2010 | 2011 | 2010 | 2012 | 2011 | ||||||||||||||||||
Exelon | $ | 26 | $ | 20 | $ | 64 | $ | 61 | $ | 16 | $ | 16 | ||||||||||||
Generation | 13 | 10 | 33 | 31 | 8 | 8 | ||||||||||||||||||
ComEd | 8 | 6 | 18 | 17 | 4 | 4 | ||||||||||||||||||
PECO | 3 | 2 | 7 | 7 | 2 | 2 | ||||||||||||||||||
BGE(a) | 2 | 2 | ||||||||||||||||||||||
BSC(b) | 1 | 2 |
(a) | BGE’s matching contributions for the three months ended March 31, 2012 include $1 million of costs incurred prior to the closing of Exelon’s merger with Constellation on March 12, 2012, which is not included in Exelon’s matching contributions for the three months ended March 31, 2012. |
(b) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above. |
11.12. 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 the 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 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 retireretired 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.million. Such revenue is intended to recover total expected operating costs, plus a return on net assets, of the two unitsunit 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 began operating under the reliability-must-run agreement effective June 1, 2011. See Note 14 of the Exelon 2011 Form 10-K for additional information.
The following table presents the activity of severance obligations for the announced Cromby and Eddystone retirements from December 31, 2011 through March 31, 2012:
Severance Benefits Obligation | Exelon and Generation | |||
Balance at December 31, 2011 | $ | 7 | ||
Cash payments | (1 | ) | ||
|
| |||
Balance at March 31, 2012 | $ | 6 | ||
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
13. Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE)
Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At March 31, 2012, there were approximately 21 million shares authorized for issuance under the LTIP. For the three months ended March 31, 2012 and 2011, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.
In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation’s 1995 Long-Term Incentive Plan, 2002 Senior Management Long-Term Incentive Plan, Amended and Restated 2007 Long-Term Incentive Plan, Amended and Restated Management Long-Term Incentive Plan and Executive Long-Term Incentive Plan (collectively and as amended, if applicable, the “Constellation Plans”). Stock-based awards granted under the Constellation Plans and held by Constellation employees were generally converted into outstanding Exelon stock-based compensation awards with the estimated fair value determined to be $71 million using the Black-Scholes model. Refer to Note 3 — Merger and Acquisitions for further information regarding the merger transaction. Specifically, as of the merger closing: (1) Exelon converted 12,037,093 outstanding shares that were subject to Constellation stock options into 11,194,151 Exelon stock options valued at $65 million; and (2) Exelon converted 165,219 Constellation no-sale restricted stock units into 153,654 Exelon no-sale restricted stock units valued at $6 million.
Exelon generally grants most of its stock options in the first quarter of each year. In connection with the merger with Constellation, the Compensation Committee of Exelon’s Board of Directors elected to delay the annual equity award grant from January 2012 to the effective date of the merger on March 12, 2012, in order to ensure that a majority of eligible employees receive grants on the same date and at the same market price.
The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011:
Three Months Ended March 31, | ||||||||
Components of Stock-Based Compensation Expense | 2012 | 2011 | ||||||
Performance share awards | $ | 16 | $ | 6 | ||||
Stock options | 7 | 5 | ||||||
Restricted stock units | 19 | 16 | ||||||
Other stock-based awards | 1 | 1 | ||||||
|
|
|
| |||||
Total stock-based compensation expense included in operating and maintenance expense | 43 | 28 | ||||||
Income tax benefit | (16 | ) | (11 | ) | ||||
|
|
|
| |||||
Total after-tax stock-based compensation expense | $ | 27 | $ | 17 | ||||
|
|
|
|
The following table presents stock-based compensation expense (pre-tax) for the three months ended March 31, 2012 and 2011:
Three Months Ended March 31, | ||||||||
Subsidiaries | 2012 | 2011 | ||||||
Generation | $ | 14 | $ | 13 | ||||
ComEd | 5 | 2 | ||||||
PECO | 3 | 2 | ||||||
BGE(a) | 2 | — | ||||||
BSC(b) | 19 | 11 | ||||||
|
|
|
| |||||
Total | $ | 43 | $ | 28 | ||||
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(a) | BGE’s stock-based compensation expense (pre-tax) for the three months ended March 31, 2012 includes $2 million of cost incurred prior to the closing of Exelon’s merger with Constellation on March 12, 2012. This amount is not included in Exelon’s stock-based compensation expense for the three months ended March 31, 2012 shown in the table titled Components of Stock-Based Compensation Expense above. BGE’s stock-based compensation expense (pre-tax) for the three months ended March 31, 2011 was $2 million. |
(b) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above. |
There were no significant stock-based compensation costs capitalized during the three months ended March 31, 2012 and 2011.
Stock Options
Non-qualified stock options are granted under the LTIP with exercise prices equal to the fair market value of the underlying stock at the date of grant. Generally, the stock options vest ratably over a four-year vesting period and expire ten years from the date of grant.
The following table presents the weighted average assumptions used to value Exelon stock options at their grant date for the three months ended March��31, 2012 and 2011:
Three Months Ended | ||||||||
2012 | 2011 | |||||||
Dividend yield | 5.28 | % | 4.84 | % | ||||
Expected volatility | 23.20 | % | 24.40 | % | ||||
Risk-free interest rate | 1.30 | % | 2.65 | % | ||||
Expected life (years) | 6.25 | 6.25 |
The assumptions above relate to Exelon stock options granted during the period and therefore do not include stock options that were converted in connection with the merger with Constellation during the three months ended March 31, 2012.
The following table summarizes Exelon’s stock option activity for the three months ended March 31, 2012:
Shares | Weighted Average Exercise Price (per share) | |||||||
Balance of shares outstanding at December 31, 2011 | 11,553,761 | $ | 48.49 | |||||
Granted | 1,840,000 | 39.79 | ||||||
Converted Constellation options | 11,194,151 | 41.35 | ||||||
Exercised | (237,490 | ) | 25.29 | |||||
Forfeited | (4,625 | ) | 53.51 | |||||
Expired | (70,098 | ) | 45.28 | |||||
|
| |||||||
Balance of shares outstanding at March 31, 2012 | 24,275,699 | $ | 44.78 | |||||
|
| |||||||
Exercisable at March 31, 2012(a) | 21,404,105 | $ | 45.33 | |||||
|
|
(a) | Includes stock options issued to retirement eligible employees. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following table summarizes Exelon’s nonvested stock option activity for the three months ended March 31, 2012:
Shares | Weighted Average Exercise Price (per share) | |||||||
Nonvested at December 31, 2011(a) | 877,050 | $ | 48.66 | |||||
Granted(b) | 1,840,000 | 39.79 | ||||||
Converted Constellation options | 11,194,151 | 41.35 | ||||||
Vested(b)(c) | (10,969,509 | ) | 41.85 | |||||
Forfeited | (70,098 | ) | 45.28 | |||||
|
| |||||||
Nonvested at March 31, 2012(a) | 2,871,594 | $ | 40.58 | |||||
|
|
(a) | Excludes 2,141,000 and 1,348,000 of stock options issued to retirement-eligible employees as of March 31, 2012 and December 31, 2011, respectively, as they are fully vested. |
(b) | Includes 8,684,709 of converted Constellation options that were vested prior to the Merger on March 12, 2012. |
(c) | Includes 1,013,000 of stock options issued to retirement-eligible employees in 2012 that vested immediately upon the employee reaching retirement eligibility. |
At March 31, 2012, $14 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 3.10 years.
Restricted Stock Units
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility.
The following table summarizes Exelon’s nonvested restricted stock unit activity for the three months ended March 31, 2012:
Shares | Weighted Average Grant Date Fair Value (per share) | |||||||
Nonvested at December 31, 2011(a) | 1,074,484 | $ | 48.08 | |||||
Granted | 1,035,280 | 39.81 | ||||||
Converted Constellation restricted stock | 825,735 | 38.91 | ||||||
Vested | (292,923 | ) | 47.71 | |||||
Forfeited | (10,784 | ) | 44.63 | |||||
Undistributed vested awards(b) | (518,064 | ) | 39.68 | |||||
|
| |||||||
Nonvested at March 31, 2012(a) | 2,113,728 | $ | 42.57 | |||||
|
|
(a) | Excludes 610,398 and 448,827 of restricted stock units issued to retirement-eligible employees as of March 31, 2012 and December 31, 2011, respectively, as they are fully vested |
(b) | Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2012. |
At March 31, 2012, Exelon had obligations related to outstanding restricted stock units not yet settled of $47 million, which are included in common stock in Exelon’s Consolidated Balance Sheets. In addition, Exelon had obligations related to outstanding restricted stock units that will be settled in cash of $1 million at March 31, 2012, which are included in deferred credits and other liabilities in Exelon’s Consolidated Balance Sheets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
project investmentDuring the three months ended March 31, 2012 and 2011, Exelon settled restricted stock units with a fair value totaling $20 million and $15 million, respectively. At March 31, 2012, $70 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.52 years.
Performance Share Awards
Performance share awards are granted under the LTIP with the 2012 and 2011 performance share awards being settled entirely in stock over the three-year vesting term. The performance shares granted prior to 2011 generally vest and settle over a three-year period with the holders receiving shares of common stock and/or cash annually during the reliability-must-runvesting period. Eddystone Unit 2 and Cromby Unit 2 began operating under
These awards are recorded at fair value at the reliability-must-run agreement effective June 1, 2011.
In connectiondate of grant with the retirementestimated grant date fair value based on the expected payout of all four units, Exelon is eliminating 253 employee positions, the majorityaward, which may range from 75% to 125% of which are located at the units to be retired. Total expected costs for Generation relatedpayout target. The portion of the award pertaining to the announced retirements75% payout floor is $37 million,valued based on Exelon’s stock price on the grant date. The expected payout in excess of the 75% floor is remeasured each reporting period based on Exelon’s current stock price and changes in the expected payout of the award; therefore this portion of the award is subject to volatility until the payout is established.
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance shares granted to retirement-eligible employees, the value of the performance shares in recognized ratably over the vesting period, which includes $14 million for estimated salary continuance and health and welfare severance benefits, a $17 million write downis the year of inventory and $6 million of shut down costs. Cash payments under this plan began in January 2010 and will continue through 2013.
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 nine months ended September 30, 2011, Generation recorded pre-tax expense of $3 million for estimated salary continuance and health and welfare severance benefits. During the nine months ended September 30, 2010, Generation recorded a pre-tax credit of $2 million for a reduction in estimated salary continuance and health and welfare severance benefits.grant.
The following table presents thesummarizes Exelon’s nonvested performance share awards activity of severance obligations for the announced Cromby and Eddystone retirements from Decemberthree months ended March 31, 2010 through September 30, 2011:2012:
Severance Benefits Obligation | Exelon and Generation | |||
Balance at December 31, 2010 | $ | 7 | ||
Severance charges recorded | 3 | |||
Cash payments | (3 | ) | ||
|
| |||
Balance at September 30, 2011 | $ | 7 | ||
|
|
Shares | Weighted Average Grant Date Fair Value (per share) | |||||||
Nonvested at December 31, 2011(a) | 346,848 | $ | 45.37 | |||||
Granted | 1,036,603 | 39.84 | ||||||
Vested | (151,700 | ) | 47.87 | |||||
Forfeited | (2,183 | ) | 43.40 | |||||
Undistributed vested awards(b) | (172,991 | ) | 40.37 | |||||
|
| |||||||
Nonvested at March 31, 2012(a) | 1,056,577 | $ | 40.41 | |||||
|
|
(a) | Excludes 274,813 and 455,418 of performance share awards issued to retirement-eligible employees as of March 31, 2012 and December 31, 2011, respectively, as they are fully vested. |
(b) | Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2012. |
During the three months ended March 31, 2012 and 2011, Exelon settled performance shares with a fair value totaling $18 million and $21 million, respectively, of which $3 million and $10 million was paid in cash, respectively. As of March 31, 2012, $41 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 2.75 years.
12.14. Earnings Per Share and Equity (Exelon)
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
awards and restricted stock outstanding under Exelon’s long-term incentive plansLTIPs 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 (in millions) used in calculating diluted earnings per share:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income | $ | 601 | $ | 845 | $ | 1,889 | $ | 2,039 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Average common shares outstanding — basic | 663 | 662 | 663 | 661 | ||||||||||||
Assumed exercise of stock options, performance share awards and restricted stock | 2 | 1 | 1 | 1 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Average common shares outstanding — diluted | 665 | 663 | 664 | 662 | ||||||||||||
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Three Months Ended March 31, | ||||||||
2012 | 2011 | |||||||
Net income | $ | 200 | $ | 668 | ||||
|
|
|
| |||||
Weighted average common shares outstanding — basic | 705 | 662 | ||||||
Assumed exercise and/or distributions of stock based awards | 2 | 2 | ||||||
|
|
|
| |||||
Weighted average common shares outstanding — diluted | 707 | 664 | ||||||
|
|
|
|
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 1011 million and 9 million for the three and nine months ended September 30,March 31, 2012 and 2011, respectively, and 9 million and 8 million for the three and nine months ended September 30, 2010, respectively.
Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3$2.327 billion as of September 30, 2011.March 31, 2012. In 2008, Exelon management decided to defer indefinitely any share repurchases.
13.15. Commitments and Contingencies (Exelon, Generation, ComEd, PECO and PECO)BGE)
For information regarding capital commitments and contingencies at December 31, 2010,2011, see Note 18 of the 2010Exelon 2011 Form 10-K. All significant changes in Exelon’s, Generation’s, ComEd’s10-K and PECO’s commitments from December 31, 2010,Note 12 of Constellation’s and all significant contingencies, are disclosed below.BGE’s 2011 Form 10-K.
Commitments
Energy Commitments
As of March 31, 2012, Generation’s ComEd’s and PECO’s shortshort- and long-term commitments relating to the salepurchases from unaffiliated utilities and purchaseothers of energy, capacity and transmission rights, are as indicated in the following table:
Net Capacity Purchases(a) | Power Purchases(b) | Transmission Rights Purchases(c) | Purchased Energy from CENG | Total | ||||||||||||||||
2012 | $ | 391 | $ | 61 | $ | 26 | $ | 677 | $ | 1,155 | ||||||||||
2013 | 360 | 67 | 32 | 583 | 1,042 | |||||||||||||||
2014 | 354 | 34 | 26 | 351 | 765 | |||||||||||||||
2015 | 351 | 9 | 13 | — | 373 | |||||||||||||||
2016 | 265 | 4 | 2 | — | 271 | |||||||||||||||
Thereafter | 668 | 6 | 36 | — | 710 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | $ | 2,389 | $ | 181 | $ | 135 | $ | 1,611 | $ | 4,316 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(a) | Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at March 31, 2012, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain capacity charges which are contingent on plant availability. |
(b) | Excludes renewable energy PPA contracts that are contingent in nature. |
(c) | Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
As part of reaching a comprehensive agreement with EDF in October 2010, the existing power purchase agreement with CENG was modified to be unit-contingent through the end of its original term in 2014. Additionally, beginning in 2015 and continuing to the end of the life of the respective plants, Generation agreed to purchase 50.01% of the available output of CENG’s nuclear plants at market prices. Generation discloses in the table commitments to purchase from CENG at fixed prices. All commitments to purchase at market prices, which include all purchases subsequent to December 31, 2014, are excluded from the table. Further, while CENG purchases from the balance sheet date through December 31, 2014 will eventually be purchased at a fixed price, only those portions of purchases that have been locked in with a fixed price have been disclosed in the table. Generation continues to own a 50.01% membership interest in CENG that is accounted for as an equity method investment. See Note 5 for more details on this arrangement.
ComEd’s, PECO’s and BGE’s electric supply procurement, curtailment services and REC and AEC purchase commitments as of September 30, 2011 changed from DecemberMarch 31, 20102012 are as follows:
Generation’s total commitments for future sales of energy to third parties increased by approximately $500 million during the nine months ended September 30, 2011, reflecting increases of approximately $658 million, $539 million, $185 million, $64 million and $238 million related to 2012, 2013, 2014, 2015 and beyond sales commitments, respectively, partially offset by a net decrease of approximately $1,184 million in 2011 due to the fulfillment of commitments, net of new commitments entered into during the nine months ended September 30, 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.
Expiration within | ||||||||||||||||||||||||||||
Total | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 and beyond | ||||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||||
Electric supply procurement(a) | $ | 1,182 | $ | 95 | $ | 367 | $ | 309 | $ | 134 | $ | 137 | $ | 140 | ||||||||||||||
Renewable energy and RECs(b) | 1,697 | 36 | 71 | 74 | 74 | 81 | 1,361 | |||||||||||||||||||||
PECO | ||||||||||||||||||||||||||||
Electric supply procurement(c) | 1,208 | 675 | 416 | 93 | 24 | — | — | |||||||||||||||||||||
AECs | 39 | 7 | 11 | 9 | 2 | 2 | 8 | |||||||||||||||||||||
Curtailment services | 12 | 12 | — | — | — | — | — | |||||||||||||||||||||
BGE | ||||||||||||||||||||||||||||
Electric supply procurement(d) | 1,299 | 646 | 544 | 109 | — | — | — | |||||||||||||||||||||
Curtailment services | 144 | 31 | 49 | 46 | 18 | — | — |
Generation’s total commitments for future net purchases of capacity from third parties decreased by $855 million during the nine months ended September 30, 2011, reflecting decreases of approximately $65 million, $66 million, $71 million, $66 million and $350 million related to 2012, 2013, 2014, 2015 and beyond net purchase commitments, respectively, due to overall hedging activity in the normal course of business. A decrease of approximately $237 million related to 2011 commitments was due to the fulfillment of commitments, net of new commitments entered into during the nine months ended September 30, 2011. See Note 6 — Derivative Financial Instruments for additional information regarding Generation’s hedging program.
In May 2011, the ICC approved procurement contracts that enable ComEd to meet its customers’ electricity requirements through May 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 $70 million for the remainder of 2011, $192 million for 2012, $292 million for 2013 and $179 million for 2014. See Note 3 — Regulatory Matters for additional information.
In May and September 2011, PECO entered into procurement contracts in order to meet a portion of its customers’ electric supply requirements for 2011 through 2013 that increased PECO’s total purchase commitments by $1 million for the remainder of 2011, $335 million for 2012, and $92 million for 2013. See Note 3 — Regulatory Matters for additional information.
(a) | ComEd entered into various contracts for the procurement of electricity that expire between 2012 and 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 4 — Regulatory Matters for additional information. |
(b) | ComEd entered into various contracts for the procurement of renewable energy and RECs that expire between 2012 and 2032. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. See Note 4 — Regulatory Matters for additional information. |
(c) | PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2012 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Program. See Note 4 — Regulatory Matters for additional information. |
(d) | BGE entered into various contracts for the procurement of electricity that expire between 2012 and 2014. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 4 — Regulatory Matters for additional information. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Fuel and Natural Gas Purchase Obligations
Generation’s and PECO’sIn addition to the energy commitments described above, Generation has commitments to purchase fuel purchase obligations as of September 30, 2011 changed from December 31, 2010 as follows:
Generation’s total fuel purchase obligationssupplies for nuclear and fossil generation decreased $1,061 million during the nine months ended September 30, 2011, primarily due(and with respect to the fulfillment of fuel procurement contracts in 2011.
PECO’s totalcoal, commitments to sell coal) and PECO and BGE have commitments to purchase natural gas, purchase obligations increased by approximately $136 million during the nine months ended September 30, 2011, reflecting increases of $49 million, $72 million, and $15 million for the remainder of 2011, 2012, and 2016 and beyond, respectively, primarily related to increased naturaltransportation, storage capacity and services to serve customers in their gas purchasedistribution service territory. As of March 31, 2012, these net commitments made in accordance with PECO’s PAPUC-approved procurement schedule.
Commercial and Construction Commitments
Exelon’s, Generation’s and ComEd’s commercial and construction commitments as of September 30, 2011, representing commitments potentially triggered by future events changed from December 31, 2010were as follows:
Exelon’s letters of credit decreased $77 million due to activity at Generation, ComEd and PECO as discussed below. Guarantees decreased by $53 million predominantly as a result of the termination of an Exelon guarantee to the NRC, net of energy trading activities at Generation as noted below. Guarantees decreased by $55 million for 2011, increased by $176 million for 2012, increased by $28 million for 2013 and decreased by $202 million for 2016 and beyond.
Generation’s letters of credit decreased by $73 million and guarantees increased by $170 million primarily as a result of energy trading activities.
Generation’s construction commitments increased by $195 million, $528 million and $445 million for 2011, 2012 and 2013, respectively, due to Generation’s commitment to construct a 230 MW solar project in Lancaster, California, as further described in Note 4 — Merger and Acquisitions.
ComEd’s letters of credit decreased by $4 million primarily due to a decrease in the letter of credit required as collateral for ComEd’s workers compensation self-insurance.
ComEd’s PJM RTEP baseline project commitments decreased by $(21) million for the nine months ended September 30, 2011, reflecting increases (decreases) of $32 million, $13 million, $(22) million, $(19) million and $(25) for 2011, 2012, 2013, 2014 and 2015, respectively, driven by changes in estimated timing and amount of project spending.
PECO’s PJM RTEP baseline project commitments increased by $ 10 million for the nine months ended September 30, 2011, reflecting increases (decreases) of $ (9) million, $ 9 million, and $ 10 million for 2013, 2014, and 2015, respectively, driven by changes in estimated timing and amount of project spending.
Expiration within | ||||||||||||||||||||||||||||
Total | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 and beyond | ||||||||||||||||||||||
Generation | $ | 8,343 | $ | 975 | $ | 1,076 | $ | 1,097 | $ | 1,129 | $ | 732 | $ | 3,334 | ||||||||||||||
PECO | 494 | 137 | 97 | 78 | 55 | 34 | 93 | |||||||||||||||||||||
BGE | 656 | 85 | 84 | 70 | 52 | 51 | 314 |
Other Purchase Obligations
Exelon’s, Generation’s, ComEd’s, PECO’s and PECO’sBGE’s other purchase obligations as of September 30, 2011,March 31, 2012, which primarily represent commitments for services, materials and information, changed from December 31, 2010are as follows:
Total | Expiration within | |||||||||||||||||||||||||||
2012 | 2013 | 2014 | 2015 | 2016 | 2017 and beyond | |||||||||||||||||||||||
Exelon | $ | 1,043 | $ | 525 | $ | 167 | $ | 127 | $ | 87 | $ | 25 | $ | 112 | ||||||||||||||
Generation | 597 | 308 | 99 | 90 | 67 | 5 | 28 | |||||||||||||||||||||
ComEd | 90 | 85 | 5 | — | — | — | — | |||||||||||||||||||||
PECO | 105 | 60 | 18 | 17 | 1 | 1 | 8 | |||||||||||||||||||||
BGE | 18 | 7 | 11 | — | — | — | — |
Exelon’s other purchase obligations increased (decreased) by $(4) million, $46 million, $7 million, $64 million, $55Construction Commitments
Generation has committed to the construction of a solar PV facility in Los Angeles County, California. Generation’s estimated commitments are $443 million and $11$445 million for the years 2012 and 2013, respectively. See Note 3 of the Exelon 2011 2012, 2013, 2014, 2015Form 10-K for additional information.
Generation has committed to the construction of approximately 404 MW of new wind facilities during 2012. Generation’s estimated commitments are approximately $460 million primarily related to the procurement of the turbines.
Refer to Note 4 — Regulatory Matters for information on investment programs associated with regulatory mandates such as ComEd’s Infrastructure Investment Plan under EIMA, PECO’s Smart Meter Procurement and 2016Installation Plan and beyond, respectively.BGE’s comprehensive smart grid initiative.
Constellation Merger Commitments
The proceeding tables do not include the merger commitments made to the State of Maryland in conjunction with the Constellation merger. See Note 3 — Merger and Acquisitions for additional information on the merger commitments.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation’s other purchase obligations increased (decreased)Contingencies
Commercial Commitments
The Registrant’s commercial commitments as of March 31, 2012, representing commitments potentially triggered by $(12) million, $11 million, $9 million, $64 million, $55 million, and $5 million for 2011, 2012, 2013, 2014, 2015 and 2016 and beyond, respectively.future events were as follows:
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Letters of credit (non-debt)(a) | $ | 2,623 | $ | 1,381 | $ | 23 | $ | 21 | $ | 1 | ||||||||||
Guarantees | 10,696 | (b) | 1,448 | (c) | 209 | (d) | 181 | (e) | 253 | (f) | ||||||||||
Nuclear insurance premiums | 2,098 | 2,098 | — | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total commercial commitments | $ | 15,417 | $ | 4,927 | $ | 232 | $ | 202 | $ | 254 | ||||||||||
|
|
|
|
|
|
|
|
|
|
ComEd’s other purchase
(a) | Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. As of March 31, 2012, guarantees of $1 million have been issued by Exelon to provide support for certain letters of credit as required by third parties. |
(b) | Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and $211 million on behalf of CENG nuclear generating facilities for credit support and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $1.6 billion at March 31, 2012, which represents the total amount Exelon could be required to fund based on March 31, 2012 market prices. |
(c) | Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts and $205 million on behalf of CENG nuclear generating facilities for credit support. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.3 billion at March 31, 2012, which represents the total amount Generation could be required to fund based on March 31, 2012 market prices. |
(d) | Primarily reflects guarantees of $200 million Trust Preferred Securities of ComEd Financing III. |
(e) | Primarily reflects guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV. |
(f) | Primarily reflects guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II. |
Nuclear Insurance (Exelon and Generation)
The Price-Anderson Act requires mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in $12.2 billion in funds available for public liability claims for any single incident at any power reactor site that exceeds the primary level of financial protection currently required ($375 million). Additionally, Generation is also required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). The maximum combined retrospective premium amount that Generation could be required to pay due to participation in the Price-Anderson Act retrospective rating plan for power reactors and the NEIL retrospective premium obligation was $2.1 billion at March 31, 2012, which is included above in the Commercial Commitments table and which does not include the potential maximum combined retrospective premium obligations increased (decreased) by $(13) millionof CENG. See the Nuclear Insurance section within Note 18 of the Exelon 2011 Form 10-K and $8 millionNote 12 of Constellation’s and BGE’s 2011 Form 10-K for 2011 and 2012, respectively.additional details on Generation’s nuclear insurance premiums.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
PECO’s other purchase obligations increased by $20 million, $29 million, $2 million and $6 million for 2011, 2012, 2013 and 2016 and beyond, 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, ExelonGeneration recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. 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 September 30, 2011.March 31, 2012 and is set to expire in 2014. The guarantee is included above in the Commercial Commitments table under Guarantees.
Indemnifications Related to Sale of Termoeléctrica del Golfo (TEG)TEG and Termoeléctrica Peñoles (TEP)TEP (Exelon and Generation)
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 September 30, 2011.March 31, 2012. Generation has not recorded a liability associated with this guarantee. The exposures covered by this guarantee expired in part during 2008. Generation expects that the remaining exposure will expire by 2014. The guarantee of $95 million is included above in the Commercial Commitments table under Guarantees.
Environmental Issues
General. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property 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, PECO and PECOBGE 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, PECO or PECOBGE is one of several PRPs that may be responsible for ultimate remediation of each location. Of the
ComEd has identified 42 sites, 13 of which have been approved for cleanup by the Illinois EPA or the US EPA and 27 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2016.
PECO has identified 27 sites, 16 of which have been approved for cleanup by ComEd, the PA DEP and 9 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2019.
BGE has identified and investigated 12 sites that BGE had owned. Two sites remain active and require some level of remediation under the direction of the Maryland Department of the Environment. The required remediation cost at these two remaining sites is not considered material.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Illinois EPA or U.S. EPA have approved the cleanup of 12 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, 27 and 11 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 2016 and 2019, respectively.
Pursuant to orders from the ICC, PAPUC and PAPUC,MDPSC, respectively, ComEd, PECO and PECOBGE are authorized to and are currently recovering environmental costs for the remediation of former MGP facility sites from customers, for which they have recorded regulatory assets. During the third quarter of 2011, ComEd and PECO each completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites; accordingly, ComEd and PECO increased their reserves and regulatory assets by $14 million and $7 million, respectively. See Note 3 —4 - Regulatory Matters for additional information regarding the associated regulatory assets.
As of September 30, 2011March 31, 2012 and December 31, 2010,2011, the Registrants had accrued the following undiscounted amounts for environmental liabilities in other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
September 30, 2011 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||
March 31, 2012 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||
Exelon | $ | 228 | $ | 174 | $ | 223 | $ | 163 | ||||||||
Generation | 46 | — | 51 | — | ||||||||||||
ComEd | 129 | 124 | 123 | 116 | ||||||||||||
PECO | 53 | 50 | 49 | 46 | ||||||||||||
December 31, 2010 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||
December 31, 2011 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||
Exelon | $ | 179 | $ | 156 | $ | 224 | $ | 168 | ||||||||
Generation | 15 | — | 47 | — | ||||||||||||
ComEd | 120 | 114 | 127 | 121 | ||||||||||||
PECO | 44 | 42 | 50 | 47 |
The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.
Water
Section 316(b) of the Clean Water Act.Section 316(b) requires that the 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. All of Generation’s and CENG’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. ThoseFor Generation those facilities are C.P. Crane, Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, H.A. Wagner, Handley, Mountain Creek, Mystic 7, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna. See Item 2ITEM 2. PROPERTIES of Exelon’s 2010the Exelon 2011 Form 10-K for a description of these facilities.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
On March 28, 2011, the EPA issued the proposed regulation under Section 316(b). The proposal does not require closed cycleclosed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment. The proposal provides the state permitting agency with discretion to determine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application of a cost–benefitcost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The rule also imposes limits on impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or similaranother technology at the intake. Exelon filed comments on the proposed regulation on August 18, 2011, stating its support for a number of its provisions (e.g., cooling towers not required as best technology available, and the use of site-specificsite-
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
specific and cost benefit analysis) while also noting a number of technical provisions that require revision to take into account existing unit operations and practices within the industry. The EPA has announced that it will publish a Notice of Data Availability to obtain public comments on the national benefits of the proposed rule and alternative compliant impingement technologies. Pursuant to a court approved Settlement Agreement, the EPA is required to approve the final rule by July 27, 2012. Until the rule is finalized, the state permitting agencies will continue to apply their best professional judgment to address impingement and entrainment.
Oyster Creek. On January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would have required, in the exercise of its best professional judgment, the installation of cooling towers as the best technology available within seven years after the effective date of the permit. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek byno later than 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 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 the limited 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 the facility’s cooling water intake through cessation of generation operations.
On December 9, 2010, Generation executed an Administrative Consent Order (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 if the conditions of the ACO are satisfied. In accordance with the ACO, on December 21, 2011, the NJDEP agreed to issue a new draftfinal NPDES permit without a requirement forthat became effective on April 12, 2012 that does not require the construction of cooling towers or other closed cycleclosed-cycle cooling facilities. On June 1, 2011, the NJDEP issued a draft permit that does not require the installation of cooling towers and is otherwise consistent with the terms of the ACO. The ACO appliesand the final permit apply only to Oyster Creek based on its unique circumstances and does not set any precedent for the ultimate compliance requirements for Section 316(b) at Exelon’s other plants.
As a result of the decision and the ACO, the expected economic useful life of Oyster Creek has been reduced.was reduced by 10 years to correspond to Exelon’s current best estimate as to the timing of ceasing generation operations at the Oyster Creek unit in 2019. The financial impacts relate primarily to accelerated depreciation and accretion expense associated with the changes in decommissioning assumptions related to Generation’s asset retirement obligation over the remaining expected economic useful life of Oyster Creek. During the nine months ended September 30, 2011, Generation made employee retention payments of approximately $14 million that will result in approximately $3 million of expense in each of years 2011 through 2015. During the nine months ended September 30, 2011, Generation recorded approximately $2 million of employee retention expense.
Salem and Other Power Generation Facilities. 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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, ExelonExelon’s and Generation’s share of the total cost of the retrofit and any resulting interim replacement power would be approximately $430 million, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment.
It is unknown at this time whether the final regulations orNJDEP permit programs will require closed-cycle cooling at Salem. In addition, the economic viability of Generation’s other power generation facilities, as well as CENG’s, without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost-benefitcost 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.Generation and CENG.
Given the uncertainties associated with the requirements that will be contained in the final rule, Generation cannot predict the eventual outcome or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its and CENG’s generating facilities and its future results of operations, cash flows and financial position.
Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the Maryland Department of the Environment relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Constellation recorded a liability in its Consolidated Balance Sheets of approximately $23 million to comply with the consent decree. As of March 31, 2012, approximately $5 million of these costs were paid, resulting in a remaining liability at March 31, 2012 of $18 million.
Alleged Conemaugh Station Water Discharge Violation. Clean Streams Violation by PA DEP.In April 2007, two environmental groups brought a Clean Water Act citizen suit against The PA DEP has alleged that GenOn Northeast Management Company (GenOn), the operator of Conemaugh Generating Station (CGS), seeking civil penalties and injunctive relief for alleged violations of CGS’s NPDES permit. On March 21, 2011, the court entered a partial summary judgment in the plaintiffs’ favor, declaring as a matter of law that discharges from CGS had violated the NPDES permit. On June 6, 2011,Clean Streams Law. GenOn is engaged in discussions with PA DEP and anticipates that the operator of CGS signed and entered with the courtparties will reach a settlement and consent decree with the plaintiffs. Under the consent decree, CGSpursuant to which GenOn will be obligated to pay a totalcivil penalty of $5 million,$500,000, of which Generation’s share is $1 million (equivalent to its 20.72% share of CGS).responsibility would be approximately $200,000.
Air
Cross State Air Pollution Rule.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 D.C. Circuit 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 D.C. Circuit 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).CSAPR. The CSAPR requires 2728 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 20112012 — 20122013 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 the use of pre-2012 allowances. Existing SO2 allowances under the ARP would remain available for use under ARP. During the third quarter of 2010, Generation recognized a lower of cost or market impairment charge of $57 million on its ARP SO2 allowances that are not expected to be used by Generation’s fossil-fuel power plants and that have not been sold forward. The impairment was recorded due to the significant decline of allowance market prices because CSAPR regulations would restrict entirely the use of ARP SO2 allowances beginning in 2012. As of September 30, 2011,March 31, 2012, Generation had $4$36 million of emission allowances carried at the lower of weighted average cost or market. Numerous entities have challenged the CSAPR in the D.C. Circuit Court, and some have requested a stay of the rule pending that Court’s consideration of the matter on the merits. Exelon
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
believes that the CSAPR is a valid exercise of the U.S. EPA’s authority and discretion under the CAA. The D.C. Circuit Court has granted permission for Exelon, as well as a number of other parties, to intervene in the litigation in support of the rule and in opposition to a stay of the rule. The Court has not set a case management schedule, and it is therefore unknown when the litigation will be resolved.
On October 14,6, 2011 and February 7, 2012, the EPA proposed for public comment certain technical corrections to CSAPR, including correction of data errors in determining generation unit allowances and state allowance budgets. These corrections will increase the number of emission allowances available under the CSAPR. In addition, the proposal defers until 2014 penalties that will involve surrender of additional allowances should states not meet certain levels of emission reductions. This deferral is intended to increase the liquidity of allowances during the initial years of transition from CAIR to the CSAPR.
EPA Toxics Rule. In March 2005,Numerous entities challenged 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 reductionCSAPR in the mercury emission cap level scheduled for 2018.D.C. Circuit Court, and some requested a stay of the rule pending the Court’s consideration of the matter on the merits. The D.C. Circuit Court later vacatedgranted permission for Exelon, as well as a number of other parties, to intervene in the CAMR onlitigation in support of the basis thatrule. On December 30, 2011, the Court granted a stay of the CSAPR, and directed the U.S. EPA had failed to properly de-listcontinue the administration of CAIR in the interim. Subsequently the Court ordered an expedited case management schedule that resulted in oral argument on April 13, 2012. It is unknown when the Court will issue its decision on the merits. Exelon believes that the CSAPR is a valid exercise of the U.S. EPA’s authority and discretion under the Clean Air Act.
EPA Mercury and Air Toxics Standards (MATS). On April 16, 2012, the MATS rule to reduce emissions of toxic air pollutants from electric generating units (EGUs) became final. The MATS rule also finalized the new source performance standards for EGUs. The MATS rule resulted from a finding by the D.C. Circuit of Appeals that the prior rule, known as the Clean Air Mercury Rule (CAMR), was invalid because it did not regulate mercury as a HAP under Section 112(c)(1) of the Clean Air Act.HAP. 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 to publish final HAP regulations by November 15, 2011.
On March 16, 2011, the U.S. EPA issued a proposedMATS rule setting national emission standards for HAPs from coal- and oil-fired electric generating facilities. EPA refers to the rule as “the Toxics Rule.” The Toxics Rule would requirerequires coal-fired electric generation plantsEGUs 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 to make capital investments and incur higher operating expenses. It is expected that smaller, older, uncontrolled coal units will retire rather than make these investments. Coal units with existing controls that do not meet the Toxics Rulerequired standards may need to upgrade existing controls or add new controls to comply. Exelon, along withIn addition, the other co-owners of Conemaugh Generating Station, are evaluating controls needed to comply with the Toxics Rule. EPA’s proposednew 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 untilMATS rule requires generating stations to meet the Toxics Rule is finalized bynew standards three years after the EPArule takes effect, April 16, 2015, with specific guidelines for an additional one or two years in December 2011.
The U.S. EPA previously announced that it would complete a review of NAAQSlimited cases. Numerous entities have challenged MATS in the 2011D.C. Circuit Court, and Exelon has petitioned the Court to intervene in support of the rule. Exelon, along with the other co-owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS.
In addition, Generation owns three base-load, coal-fired generation units in Maryland that were acquired in the merger with Constellation — 2012 timeframeBrandon Shores, H.A. Wagner and C.P. Crane. However, in connection with certain of the regulatory approvals required for particulate matter, nitrogen dioxide, sulfur dioxide, and lead. This review could result in more stringent emissions limits on fossil-fired electricthe merger Exelon agreed to divest these generating stations. It is anticipated that these plants are well positioned to comply with CSAPR and MATS since Maryland has adopted SO2, NOx, and mercury emission limits under its Healthy Air Act and Clean Power Rule that are generally consistent with the requirements of CSAPR and MATS.
In September 2011, the U.S. EPA withdrew its reconsideration of the NAAQS standard for ozone, which is next scheduled for reconsideration in 2013.
Additionally,addition, as of September 30, 2011,March 31, 2012, Exelon hashad a $649$663 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases that extendextending through 2028-2032. While Exelon currently estimates the value of these plants at the end of the lease term will be in excess of the recorded residual lease values, final applications of the CSAPR and HAPMATS regulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material.
NAAQS. The U.S. EPA previously announced that it would complete a review of NAAQS in the 2011 — 2012 timeframe for particulate matter, nitrogen dioxide, sulfur dioxide, and lead. This review could
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
result in more stringent emissions limits on fossil-fired electric generating stations. In September 2011, the U.S. EPA withdrew its reconsideration of the NAAQS standard for ozone, which is next scheduled for reconsideration in 2013.
Notices and Finding of Violations Related to Electric Generation Stations. On August 6, 2007, ComEd received a 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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.
The generating stations that are the subject of the NOV are currently owned and operated by Midwest Generation, which purchased the stations in December 1999 from ComEd. Under the terms of the sale agreement, Midwest Generation and its affiliate, Edison Mission Energy (EME), assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance of the stations with environmental laws before the purchase of the stations by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale.
In August 2009, the DOJ 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 Court 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. On March 16, 2011, the U.S. District Court granted ComEd’s motion to dismiss the May 2010 complaint. The dismissal order will not be final untilOn January 3, 2012, upon leave of the underlying case against Midwest Generation is resolved, soU.S. District Court, the government plaintiffs cannot appeal ComEd’sparties appealed the dismissal before that time without leave of court. The government plaintiffs have requested an appeal conditional upon a stayComEd to the U.S. Circuit Court of the remaining case until the appeal is completed. A ruling on the merits of allowing a stay is set for November 10, 2011.Appeals.
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 in light of the District Court decision the likelihood of loss is 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.
Solid and Hazardous Waste
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation. 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 approximately $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 radiological contamination. On September 30, 2011, the PRPs submitted the final supplemental feasibility study to the EPA for review. It is anticipated that the EPA will propose a remedy in the second quarter of 2012, which will be subject to public comment. Thereafter the EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. An excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require the use of an excavation remedy is remote.
On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U. S.U.S. government’s Manhattan Project. Cotter purchased the residues in 19671969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $100 million. The DOJ and the PRPs have agreed to toll the statute of limitations until August 2012 so that settlement discussions can proceed. Based on Exelon’s preliminary review, it appears probable that Exelon has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.
Climate Change Regulation
On February 28, 2012, and April 12, 2012, two lawsuits were filed in the U.S. District Court for the Eastern District of Missouri against 15 and 14 defendants respectively, including Exelon, Generation and ComEd (the “Exelon defendants”). The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the defendants’ negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. The Exelon defendants are parties to the actions based on their prior ownership of Cotter Corporation as described above. Due to the early stage of the litigation, Exelon is or may become,unable to determine the extent of its potential liability, if any.
68th Street Dump. In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The potentially responsible parties submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the EPA are still subject to climate change regulation or legislation atEPA review and selection of a remedy, the international, Federal, regional and state levels.
International Climate Change Regulation. At the international level, the United States is currently not a partyrange of estimated clean-up costs 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 conclusionbe allocated among all of the December 2007 United Nations Climate Change ConferencePRPs is in Bali, Indonesia, the Bali Action Plan was adopted, which identifiesrange of $50 million and $64 million. The EPA is expected to make a work group, process and timeline for the considerationfinal selection 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 conclusionone of the 15th Conferencealternatives in 2012. Since the EPA has not selected the remedy and the allocation 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 meeting will be held in December 2011 in South Africa.clean-up costs
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Numerous bills were introduced in Congress duringamong the 111PRPs has not been determined, an estimate of the range of BGE’s possible loss cannot be determined. BGE is indemnified by a wholly owned subsidiary of Generation for most of the costs related to this settlement and clean-up of the site.
th Congress that addressClimate Change Regulation. Exelon is subject to climate change from different perspectives, including direct regulation of GHG emissionsor legislation at the international, Federal, regional and the establishment of Federal Renewable Portfolio Standards, but none were passed by both houses of Congress. In reaction to the U.S. EPA’s proposed regulation of GHG emissions, various bills have been introduced in the U.S. House of Representatives that would prohibit or impede the U.S. EPA’s rulemaking efforts. The timing of the consideration of such legislation is unknown.
state levels. In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. Consequently, on December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks effective on January 2, 2011. While such regulations do not specifically address stationary sources, such as a generating plant, it is the U.S. EPA’s position that the regulation of GHGs under the mobile source provisions of the Clean Air Act has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO2 equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO2 equivalent basis. These thresholds became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. On April 13, 2012, the U.S. EPA published proposed regulations for new source performance standards (NSPS) for GHG emissions from new fossil-fueled power plants, greater than 25 MW, that would require the plants to limit CO2 emissions to a thirty-year average of less than 1000 pounds per MWh (less than 1800 pounds per MWh for the first ten years and less than 600 pounds per MWh thereafter). Under the regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case-by-case basis. ExelonGeneration could be significantly affected by the regulations if it were to build new plants or modify existing plants. In addition EPA is preparing a proposed rule to establish new source performance standards for greenhouse gas emissions from power plants as part of a court settlement.
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.
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, but no actions have been taken on the recommendations.
At the state level, the PCCA was signed into law in Pennsylvania in July 2008. The PCCA requires, among other things, that: a Climate Change Advisory Committee be formed; a report on the potential impact of climate change in Pennsylvania be developed; the PA DEP develop a GHG inventory for Pennsylvania; a voluntary GHG registry be identified; and 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Litigation and Regulatory Matters
Except to the extent noted below, the circumstances set forth in Note 18 of the 2010Exelon 2011 Form 10-K and Note 12 of Constellation’s and BGE’s 2011 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.
Asbestos Personal Injury Claims (Exelon, Generation and BGE)
Exelon and Generation
.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.
At September 30, 2011March 31, 2012 and December 31, 2010,2011, Generation had reserved approximately $51$47 million and $49 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2011,March 31, 2012, approximately $15$13 million of this amount related to 178172 open claims presented to Generation, while the remaining $36$34 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.
ExelonBGE.Since 1993, BGE and certain Constellation subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Savings Plan Claim. On September 11, 2006, five(Dollars in millions, except per share data, unless otherwise noted)
Constellation knew of and exposed individuals claiming to an asbestos hazard. In addition to BGE and Constellation, numerous other parties are defendants in these cases.
Approximately 480 individuals who were never employees of BGE or Constellation have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third party claims brought by other defendants may also be participantsfiled against BGE and former Constellation subsidiaries now owned by Generation in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or Constellation and a small minority of these cases has been resolved for amounts that were not material to its financial results.
Discovery begins in these cases once they are placed on the trial docket. At present, none of the pending cases are set for trial. Given the limited discovery, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the possible loss relating to these claims. The specific facts not known include:
the identity of the facilities at which the plaintiffs allegedly worked as contractors;
the names of the plaintiffs’ employers;
the dates on which and the places where the exposure allegedly occurred; and
the facts and circumstances relating to the alleged exposure.
Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the Exelon Corporation Employee Savings Plan, Plan #003 (Savings Plan),actions.
Gain on U.S. Department of Energy Settlements (Exelon and Generation)
CENG is currently in negotiations with the DOE to recover damages caused by the DOE’s failure to comply with legal and contractual obligations to dispose of spent nuclear fuel related to the Nine Mile Point nuclear power plant. Any funds received from the DOE related to costs incurred prior to November 6, 2009 will belong to Generation. We have recorded a pre-acquisition contingent asset of approximately $25 million related to Generation’s share of the potential settlement. See Note 3 — Mergers and Acquisitions for additional information on the merger.
Federal Energy Regulatory Commission Investigation (Exelon and Generation)
On January 30, 2012, FERC published a notice on its website regarding a non-public investigation of certain of Constellation’s power trading activities in and around the New York ISO from September 2007 through December 2008. Prior to the merger, Constellation announced on March 9, 2012, that it had resolved the FERC investigation. Under the settlement, Constellation agreed to pay a $135 million civil penalty and $110 million in disgorgement. The disgorgement amount will be disbursed in two ways. First, Constellation will provide $1 million each to six U.S. regional grid operators for the purpose of improving their surveillance and analytic capabilities. The remainder of the disgorgement amount was deposited in a fund that will be administered by a FERC ALJ. State agencies in New York, New England and PJM (the regional grid operator for 13 states and the District of Columbia) will be eligible to make claims against the fund on behalf of electric energy consumers in those states.
During the three months ended March 31, 2012, Generation recorded expense of $195 million in operating and maintenance expense, with the remaining $50 million recorded as a Constellation pre-acquisition contingency. As of March 31, 2012, the full amount of the civil penalty and disgorgement was paid. See Note 3 — Merger and Acquisitions for additional information on the merger.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Continuous Power Interruption (ComEd)
The Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) 30,000 or more customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law.
On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd’s service territory, as well as for five other storm systems that affected ComEd’s customers during June and July 2011. The ICC is currently conducting a proceeding to assess ComEd’s request. In the absence of a favorable determination from the ICC, some ComEd customers affected by the outages could seek recovery of their actual, non-consequential damages, and the local governments in the areas in which those customers are located could seek recovery of emergency and contingency expenses. On January 27, 2012, the ICC Staff and the Illinois Attorney General (AG) filed testimony in the ICC proceeding. They both disagree with ComEd’s interpretation that the statute does not apply to any of the individual continuous power interruptions caused by the 2011 storms. Additionally, the ICC witness supports granting a putativewaiver for the three of the six storms, while the AG asserts that ComEd should be held responsible for the damages from all the storms. On March 30, 2012, ComEd filed responsive testimony in the ICC proceeding to further support its position that no compensation is required.
In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard. On February 14, 2012, the ICC Staff and the AG filed testimony in the proceeding. ICC staff has recommended that the ICC issue ComEd a waiver based on the extreme weather conditions. The AG has taken the same position as that filed in the summer storm system waiver noted above. Additional active proceedings related to storms of lesser collective impact are also pending. Both of the above proceedings have been set for hearing in July 2012. The ultimate outcomes of these proceedings are uncertain, and the amount of damages, if any, which might be asserted, cannot be reasonably estimated at this time, but may be material to ComEd’s results of operations and cash flows.
Securities Class Action (Exelon)
Three federal securities class action lawsuitlawsuits were filed in the U.S.United States District CourtCourts for the NorthernSouthern District of Illinois. The complaint names as defendants Exelon, its Director of Employee Benefit Plans and Programs, the Employee Savings Plan Investment Committee, the CompensationNew York and the Risk Oversight CommitteesDistrict of Exelon’s BoardMaryland between September 2008 and November 2008 against Constellation. The cases were filed on behalf of Directorsa proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation between January 30, 2008 and membersSeptember 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation, a number of those committees. On December 9, 2009,its former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation’s June 27, 2008 offering of Debentures. The securities class actions also allege that Constellation issued false or misleading statements or was aware of material undisclosed information which contradicted public statements including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions seek, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The Southern District Courtof New York granted the defendants’ motion to transfer the two securities class actions filed in Maryland to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On June 18, 2009, the court appointed a lead plaintiff, who filed a consolidated amended complaint on September 17, 2009. On November 17, 2009, the defendants moved to dismiss the consolidated amended complaint in its entirety. On August 13, 2010, the District Court of Maryland issued a ruling on the motion to dismiss, holding that the plaintiffs failed to state a claim with respect to the claims of the common shareholders under the Securities Exchange Act of 1934 and limiting the suit to those persons who purchased Debentures in the June 2008 offering. In August 2011, plaintiffs requested permission from the court to file a third amended complaint in an effort to attempt to revive the claims of the common shareholders. Constellation filed an objection to the plaintiffs’ request for permission to file a third amended complaint and enter judgment in favoron March 28, 2012, the District Court of Maryland denied the plaintiffs’ request for permission to revive the claims of the defendants. Thecommon shareholders. Given that limited discovery has occurred, that the court has not certified any class and the plaintiffs appealed the District Court’s dismissal ofhave not quantified their potential damage claims, Exelon is unable at this time to the U.S. Court of Appeals for the Seventh Circuit who affirmed the dismissalprovide an estimate of the class action lawsuit on September 6, 2011. The plaintiffs have 90 daysrange of possible loss relating to file a petition requesting that the case be heard by the U.S. Supreme Court. While Exelon believes it will prevail,these proceedings or to determine the ultimate outcome of the savings plan claim is uncertain, cannot be estimated and it may have a material impactsecurities class actions or their possible effect on Exelon’s results of operations, cash flows orits financial position.results.
Exelon,General (Exelon, Generation, ComEd, PECO and PECOBGE)
General. The Registrants are involved in various other individually immaterial litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
Income Taxes (Exelon, Generation, ComEd, PECO and BGE)
See Note 89 — Income Taxes for information regarding the Registrants’ income tax refund claims and uncertaincertain tax positions, including the 1999 sale of fossil generating assets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
14.16. Supplemental Financial Information (Exelon, Generation, ComEd, PECO and PECO)BGE)
Supplemental Statement of Operations Information
The following tables provide additional information about the Registrants’ Consolidated Statements of Operations for the three and nine months ended September 30, 2011March 31, 2012 and 2010:2011:
Three Months Ended September 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 319 | $ | 139 | $ | 125 | $ | 48 | ||||||||
Regulatory assets | 13 | — | 10 | 3 | ||||||||||||
Nuclear fuel(a) | 200 | 200 | — | — | ||||||||||||
Asset retirement obligation accretion(b) | 56 | 56 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total depreciation, amortization and accretion | $ | 588 | $ | 395 | $ | 135 | $ | 51 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Nine Months Ended September 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 947 | $ | 416 | $ | 374 | $ | 141 | ||||||||
Regulatory assets | 40 | — | 31 | 9 | ||||||||||||
Nuclear fuel(a) | 556 | 556 | — | — | ||||||||||||
Asset retirement obligation accretion(b) | 159 | 159 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total depreciation, amortization and accretion | $ | 1,702 | $ | 1,131 | $ | 405 | $ | 150 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Three Months Ended September 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 288 | $ | 121 | $ | 119 | $ | 43 | ||||||||
Regulatory assets(c) | 290 | — | 7 | 283 | ||||||||||||
Nuclear fuel(a) | 173 | 173 | — | — | ||||||||||||
Asset retirement obligation accretion(b) | 49 | 49 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total depreciation, amortization and accretion | $ | 800 | $ | 343 | $ | 126 | $ | 326 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Nine Months Ended September 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||
Property, plant and equipment | $ | 845 | $ | 344 | $ | 352 | $ | 128 | ||||||||
Regulatory assets(c) | 766 | — | 34 | 731 | ||||||||||||
Nuclear fuel(a) | 496 | 496 | — | — | ||||||||||||
Asset retirement obligation accretion(b) | 148 | 147 | 1 | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total depreciation, amortization and accretion | $ | 2,255 | $ | 987 | $ | 387 | $ | 859 | ||||||||
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Other, Net | ||||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||||
Net realized income on decommissioning trust funds(a) | ||||||||||||||||||||
Regulatory Agreement Units | $ | 60 | $ | 60 | $ | — | $ | — | $ | — | ||||||||||
Non-Regulatory Agreement Units | 48 | 48 | — | — | — | |||||||||||||||
Net unrealized income on decommissioning trust funds | ||||||||||||||||||||
Regulatory Agreement Units | 247 | 247 | — | — | — | |||||||||||||||
Non-Regulatory Agreement Units | 65 | 65 | — | — | — | |||||||||||||||
Net unrealized income on pledged assets | ||||||||||||||||||||
Zion Station decommissioning | 35 | 35 | — | — | — | |||||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | (277 | ) | (277 | ) | — | — | — | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total decommissioning-related activities | 178 | 178 | — | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Investment income | 4 | — | 1 | 1 | 3 | |||||||||||||||
Long-term lease income | 7 | — | — | — | — | |||||||||||||||
AFUDC — Equity | 3 | — | 1 | 1 | 3 | |||||||||||||||
Other | 2 | — | 2 | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Other, net | $ | 194 | $ | 178 | $ | 4 | $ | 2 | $ | 6 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Other, Net | ||||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||||
Net realized income on decommissioning trust funds(a) | ||||||||||||||||||||
Regulatory Agreement Units | $ | 43 | $ | 43 | $ | — | $ | — | $ | — | ||||||||||
Non-Regulatory Agreement Units | 10 | 10 | — | — | — | |||||||||||||||
Net unrealized income on decommissioning trust funds | ||||||||||||||||||||
Regulatory Agreement Units | 111 | 111 | — | — | — | |||||||||||||||
Non-Regulatory Agreement Units | 43 | 43 | — | — | — | |||||||||||||||
Net unrealized gains on pledged assets | ||||||||||||||||||||
Zion Station decommissioning | 23 | 23 | — | — | — | |||||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | (151 | ) | (151 | ) | — | — | — | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total decommissioning-related activities | 79 | 79 | — | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Investment income | 1 | — | — | 1 | 4 | |||||||||||||||
Long-term lease income | 7 | — | — | — | — | |||||||||||||||
Interest income related to uncertain income tax provisions | 3 | — | 1 | — | ||||||||||||||||
AFUDC — Equity | 5 | — | 1 | 4 | 4 | |||||||||||||||
Other | (1 | ) | (4 | ) | 2 | 1 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Other, net | $ | 94 | $ | 75 | $ | 4 | $ | 6 | $ | 8 | ||||||||||
|
|
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Three Months Ended September 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds(a) — Regulatory Agreement Units | $ | 16 | $ | 16 | $ | — | $ | — | ||||||||
Non-Regulatory Agreement Units | 13 | 13 | — | — | ||||||||||||
Net unrealized losses on decommissioning trust funds — | (363 | ) | (363 | ) | — | — | ||||||||||
Non-Regulatory Agreement Units | (141 | ) | (141 | ) | — | — | ||||||||||
Net unrealized losses on pledged assets — | (4 | ) | (4 | ) | — | — | ||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | 281 | 281 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total decommissioning-related activities | (198 | ) | (198 | ) | — | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Investment income | 1 | — | — | 1 | ||||||||||||
Long-term lease income | 7 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions | 7 | — | 12 | — | ||||||||||||
AFUDC — Equity | 4 | — | 2 | 2 | ||||||||||||
Bargain purchase gain related to Wolf Hollow acquisition | 36 | 36 | — | — | ||||||||||||
Other | — | (2 | ) | 2 | — | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Other, net | $ | (143 | ) | $ | (164 | ) | $ | 16 | $ | 3 | ||||||
|
|
|
|
|
|
|
| |||||||||
Nine Months Ended September 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds(a) — Regulatory Agreement Units | $ | 97 | $ | 97 | $ | — | $ | — | ||||||||
Non-Regulatory Agreement Units | 39 | 39 | — | — | ||||||||||||
Net unrealized losses on decommissioning trust funds — | (223 | ) | (223 | ) | — | — | ||||||||||
Non-Regulatory Agreement Units | (88 | ) | (88 | ) | — | — | ||||||||||
Net unrealized income on pledged assets — | 41 | 41 | — | — | ||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | 60 | 60 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total decommissioning-related activities | (74 | ) | (74 | ) | — | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Investment income | 3 | — | — | 3 | ||||||||||||
Long-term lease income | 21 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions | 53 | 33 | 13 | 1 | ||||||||||||
AFUDC — Equity | 14 | — | 6 | 8 | ||||||||||||
Bargain purchase gain related to Wolf Hollow acquisition | 36 | 36 | — | — | ||||||||||||
Other | (2 | ) | (7 | ) | 5 | (1 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Other, net | $ | 51 | $ | (12 | ) | $ | 24 | $ | 11 | |||||||
|
|
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Three Months Ended September 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds(a) — Regulatory Agreement Units | $ | 41 | $ | 41 | $ | — | $ | — | ||||||||
Non-Regulatory Agreement Units | 12 | 12 | — | — | ||||||||||||
Net unrealized losses on decommissioning trust funds — | 324 | 324 | — | — | ||||||||||||
Non-Regulatory Agreement Units | 107 | 107 | — | — | ||||||||||||
Regulatory offset to decommissioning trust fund-related | (292 | ) | (292 | ) | — | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total decommissioning-related activities | 192 | 192 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Long-term lease income | 7 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions | — | — | 1 | — | ||||||||||||
AFUDC — Equity | 2 | — | — | 2 | ||||||||||||
Other | 5 | — | 2 | 1 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Other, net | $ | 206 | $ | 192 | $ | 3 | $ | 3 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Nine Months Ended September 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other, Net | ||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||
Net realized income on decommissioning trust funds(a) — Regulatory Agreement Units | $ | 140 | $ | 140 | $ | — | $ | — | ||||||||
Non-Regulatory Agreement Units | 38 | 38 | — | — | ||||||||||||
Net unrealized losses on decommissioning trust funds — | 117 | 117 | — | — | ||||||||||||
Non-Regulatory Agreement Units | 48 | 48 | — | — | ||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | (206 | ) | (206 | ) | — | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total decommissioning-related activities | 137 | 137 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Long-term lease income | 20 | — | — | — | ||||||||||||
Interest income related to uncertain income tax positions | — | — | 3 | — | ||||||||||||
AFUDC — Equity | 6 | — | 1 | 5 | ||||||||||||
Other | 15 | 1 | 10 | 1 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Other, net | $ | 178 | $ | 138 | $ | 14 | $ | 6 | ||||||||
|
|
|
|
|
|
|
|
(a) | Includes investment income and realized gains and losses on sales of investments of the trust funds. |
(b) | Includes the elimination of NDT fund-related activity for the Regulatory Agreement Units, including the elimination of net realized income taxes related to all NDT fund activity for those units. See Note 12 of the |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the ninethree months ended September 30, 2011March 31, 2012 and 2010:2011:
Nine Months Ended September 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other non-cash operating activities: | ||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 407 | $ | 187 | $ | 160 | $ | 24 | ||||||||
Provision for uncollectible accounts | 97 | — | 49 | 48 | ||||||||||||
Stock-based compensation costs | 55 | — | — | — | ||||||||||||
Other decommissioning-related activity(a) | 62 | 62 | — | — | ||||||||||||
Energy-related options(b) | 102 | 102 | — | — | ||||||||||||
Amortization of regulatory asset related to debt costs | 16 | — | 14 | 2 | ||||||||||||
Uncollectible accounts recovery, net | 14 | — | 14 | — | ||||||||||||
Discrete impacts from 2010 Rate Case order(c) | (32 | ) | — | (32 | ) | — | ||||||||||
Bargain purchase gain related to Wolf Hollow Acquisition | (36 | ) | (36 | ) | — | — | ||||||||||
Other | 18 | 47 | 5 | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total other non-cash operating activities | $ | 703 | $ | 362 | $ | 210 | $ | 74 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Changes in other assets and liabilities: | ||||||||||||||||
Under-recovered energy and transmission costs | (9 | ) | — | (20 | ) | 11 | ||||||||||
Other current assets | (163 | ) | (46 | ) | (13 | ) | (59 | )(d) | ||||||||
Other noncurrent assets and liabilities | 83 | (19 | ) | 62 | 20 | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total changes in other assets and liabilities | $ | (89 | ) | $ | (65 | ) | $ | 29 | $ | (28 | ) | |||||
|
|
|
|
|
|
|
| |||||||||
Nine Months Ended September 30, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||
Other non-cash operating activities: | ||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 435 | $ | 202 | $ | 161 | $ | 35 | ||||||||
Provision for uncollectible accounts | 92 | — | 44 | 48 | ||||||||||||
Stock-based compensation costs | 35 | — | — | — | ||||||||||||
Other decommissioning-related activity(a) | (46 | ) | (46 | ) | — | — | ||||||||||
Energy-related options(b) | (54 | ) | (54 | ) | — | — | ||||||||||
Amortization of regulatory asset related to debt costs | 18 | — | 15 | 3 | ||||||||||||
Accrual for Illinois utility distribution tax refund(e) | (25 | ) | — | (25 | ) | — | ||||||||||
Uncollectible accounts recovery, net(f) | (36 | ) | — | (36 | ) | — | ||||||||||
Impairment of certain emission allowances | 57 | 57 | — | — | ||||||||||||
Other | (8 | ) | 5 | 3 | (1 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total other non-cash operating activities | $ | 468 | $ | 164 | $ | 162 | $ | 85 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Changes in other assets and liabilities: | ||||||||||||||||
Under/over-recovered energy and transmission costs | 154 | — | 151 | 3 | ||||||||||||
Other current assets | (81 | ) | (46 | ) | 10 | (51 | )(d) | |||||||||
Other noncurrent assets and liabilities | (114 | ) | (6 | ) | (247 | )(g) | 84 | |||||||||
|
|
|
|
|
|
|
| |||||||||
Total changes in other assets and liabilities | $ | (41 | ) | $ | (52 | ) | $ | (86 | ) | $ | 36 | |||||
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Depreciation, amortization, accretion and depletion | ||||||||||||||||||||
Property, plant and equipment | $ | 354 | $ | 150 | $ | 131 | $ | 51 | $ | 61 | ||||||||||
Regulatory assets | 25 | — | 18 | 2 | 18 | |||||||||||||||
Amortization of intangible assets | 3 | 3 | — | — | — | |||||||||||||||
Amortization of energy contract assets and liabilities(a) | 131 | 131 | — | — | — | |||||||||||||||
Nuclear fuel(a) | 207 | 207 | — | — | — | |||||||||||||||
Asset retirement obligation accretion(b) | 56 | 56 | — | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total depreciation, amortization and accretion | $ | 776 | $ | 547 | $ | 149 | $ | 53 | $ | 79 | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Three Months Ended March 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||||||
Property, plant and equipment | $ | 313 | $ | 139 | $ | 122 | $ | 46 | $ | 57 | ||||||||||
Regulatory assets | 14 | — | 12 | 2 | 20 | |||||||||||||||
Nuclear fuel(a) | 174 | 174 | — | — | — | |||||||||||||||
Asset retirement obligation accretion(b) | 51 | 51 | — | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total depreciation, amortization and accretion | $ | 552 | $ | 364 | $ | 134 | $ | 48 | $ | 77 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(a) | Included in purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
(b) | Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Three Months Ended March 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Other non-cash operating activities: | ||||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 181 | $ | 81 | $ | 69 | $ | 13 | $ | 16 | ||||||||||
Provision for uncollectible accounts | 40 | (9 | ) | 22 | 24 | 8 | ||||||||||||||
Stock-based compensation costs | 39 | — | — | — | — | |||||||||||||||
Other decommissioning-related activity(a) | (71 | ) | (71 | ) | — | — | — | |||||||||||||
Energy-related options(b) | 28 | 28 | — | — | — | |||||||||||||||
Amortization of regulatory asset related to debt costs | 6 | — | 4 | 1 | 1 | |||||||||||||||
Amortization of rate stabilization deferral | 3 | — | — | — | 13 | |||||||||||||||
Discrete impacts from EIMA(c) | (38 | ) | — | (38 | ) | — | — | |||||||||||||
Merger-related commitments(d) | 331 | 35 | — | — | 141 | |||||||||||||||
Equity in loss of unconsolidated subsidiaries | 22 | 22 | — | — | — | |||||||||||||||
Other | (11 | ) | 4 | 3 | 2 | (1 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total other non-cash operating activities | $ | 530 | $ | 90 | $ | 60 | $ | 40 | $ | 178 | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Changes in other assets and liabilities: | ||||||||||||||||||||
Under/over-recovered energy and transmission costs | (25 | ) | — | (38 | ) | 13 | (10 | ) | ||||||||||||
Other regulatory assets and liabilities | (97 | ) | — | (16 | ) | 3 | (16 | ) | ||||||||||||
Other current assets | (18 | ) | (122 | ) | 1 | (134 | )(e) | 31 | ||||||||||||
Other noncurrent assets and liabilities | 18 | 42 | (19 | ) | 8 | 7 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total changes in other assets and liabilities | $ | (122 | ) | $ | (80 | ) | $ | (72 | ) | $ | (110 | ) | $ | 12 | ||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Non-cash investing and financing activities: | ||||||||||||||||||||
Merger with Constellation, common stock issued | $ | 7,365 | $ | 5,272 | $ | — | $ | — | $ | — | ||||||||||
Three Months Ended March 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Other non-cash operating activities: | ||||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 136 | $ | 62 | $ | 54 | $ | 8 | $ | 11 | ||||||||||
Provision for uncollectible accounts | 45 | — | 19 | 26 | 9 | |||||||||||||||
Stock-based compensation costs | 28 | — | — | — | — | |||||||||||||||
Other decommissioning-related activity(a) | (32 | ) | (32 | ) | — | — | — | |||||||||||||
Energy-related options(b) | 34 | 34 | — | — | — | |||||||||||||||
Amortization of regulatory asset related to debt costs | 6 | — | 5 | 1 | 1 | |||||||||||||||
Uncollectible accounts recovery, net | 4 | — | 4 | — | — | |||||||||||||||
Amortization of rate stabilization deferral | — | — | — | — | 14 | |||||||||||||||
Deferral of storm costs | — | — | — | — | (16 | ) | ||||||||||||||
Other | 2 | 8 | — | — | (3 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total other non-cash operating activities | $ | 223 | $ | 72 | $ | 82 | $ | 35 | $ | 16 | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Changes in other assets and liabilities: | ||||||||||||||||||||
Under/over-recovered energy and transmission costs | (60 | ) | — | (29 | ) | (31 | ) | 3 | ||||||||||||
Other regulatory assets and liabilities | 3 | — | 5 | (2 | ) | (3 | ) | |||||||||||||
Other current assets | (169 | ) | (20 | ) | (8 | ) | (136 | )(e) | 31 | |||||||||||
Other noncurrent assets and liabilities | 8 | — | (3 | ) | 7 | (5 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total changes in other assets and liabilities | $ | (218 | ) | $ | (20 | ) | $ | (35 | ) | $ | (162 | ) | $ | 26 | ||||||
|
|
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(a) | Includes the elimination of NDT fund-related activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 12 of the |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. |
(c) |
|
(d) | See Note 3 — Mergers and Acquisitions for more information on merger-related commitments. |
(e) | Relates primarily to prepaid utility taxes. |
|
|
|
DOE Smart Grid Investment Grant (Exelon, PECO and PECO)BGE). For the ninethree months ended September 30, 2011,March 31, 2012, Exelon, PECO and PECOBGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $29$30 million, $20 million and $10 million, respectively, and reimbursements of $45$35 million, $21 million and $14 million, respectively, related to PECO’s and BGE’s DOE SGIG.SGIG programs. For the three months ended March 31, 2011, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $15 million, $9 million and $6 million, respectively, and reimbursements of $18 million, $5 million and $13 million, respectively, related to PECO’s and BGE’s DOE SGIG programs. See Note 3 —4 - Regulatory Matters for additional information regarding the DOE SGIG.
Repurchase Agreements (Exelon and Generation). Repurchase Agreements are financial instruments used to fund short-term liquidity requirements where a counterparty typically agrees to sell the financial instrument and repurchase it the following day. Exelon and Generation have historically presented purchases and sales of Repurchase Agreements with a maturity of three months or less on a gross basis in ‘Investments in NDT funds’ and ‘Proceeds from NDT fund sales’, respectively, within Exelon and Generation’s Consolidated Statements of Cash Flows. Due to the nature and volume of these transactions, effective December 31, 2010, Exelon and 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 nine months ended September 30, 2010 was adjusted to reflect this change in presentation, which is presented in the following table:
Nine Months Ended September 30, 2010 | ||||||||||||
As previously stated | Adjustments | As Adjusted | ||||||||||
Proceeds from NDT fund sales | $ | 21,869 | $ | (19,113 | ) | $ | 2,756 | |||||
Investments in NDT funds | $ | (21,977 | ) | $ | 19,113 | $ | (2,864 | ) |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2011March 31, 2012 and December 31, 2010.2011.
September 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||||||||||||||||||||||
March 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||||||||||||||||
Property, plant and equipment: | ||||||||||||||||||||||||||||||||||||
Accumulated depreciation | $ | 10,919 | (a) | $ | 5,394 | (a) | $ | 2,672 | $ | 2,624 | $ | 11,244 | (a) | $ | 5,563 | (a) | $ | 2,769 | $ | 2,691 | $ | 2,508 | ||||||||||||||
Accounts receivable: | ||||||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts | 244 | 30 | 90 | 124 | 317 | 82 | 90 | 111 | 34 | |||||||||||||||||||||||||||
December 31, 2010 | Exelon | Generation | ComEd | PECO | ||||||||||||||||||||||||||||||||
December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||||||||||||||||
Property, plant and equipment: | ||||||||||||||||||||||||||||||||||||
Accumulated depreciation | $ | 10,064 | (b) | $ | 4,880 | (b) | $ | 2,428 | $ | 2,531 | $ | 10,959 | (b) | $ | 5,313 | (b) | $ | 2,750 | $ | 2,662 | $ | 2,465 | ||||||||||||||
Accounts receivable: | ||||||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts | 228 | 32 | 80 | 116 | 199 | 29 | 78 | 92 | 38 |
(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 net receivable balance for
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
installment plans with terms greater than one year was $23$17 million and $22$21 million as of September 30, 2011March 31, 2012 and December 31, 2010,2011, 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 2010Exelon 2011 Form 10-K. As of September 30, 2011, the allowance for uncollectible accounts was $20 million, an increase of $1 million from December 31, 2010. The increase 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 associated with these receivables at September 30, 2011March 31, 2012 of $20$13 million consists of $1 million, $4 million and $16$8 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 20102011 of $19$17 million consists of $1 million, $5$3 million and $13 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of September 30, 2011March 31, 2012 and December 31, 20102011 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 2010Exelon 2011 Form 10-K.
Accumulated Other Comprehensive Income (Loss)
The following tables provide information about accumulated OCI (loss) recorded (after tax) within the Consolidated Balance Sheets of the Registrants as of March 31, 2012 and December 31, 2011:
March 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Accumulated other comprehensive income (loss) | ||||||||||||||||||||
Net unrealized gain on cash flow hedges | $ | 703 | $ | 1,167 | $ | — | $ | — | $ | — | ||||||||||
Pension and non-pension postretirement benefit plans | (2,904 | ) | — | — | — | — | ||||||||||||||
Unrealized gain on marketable securities | 2 | — | — | 1 | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total accumulated other comprehensive income (loss) | $ | (2,199 | ) | $ | 1,167 | $ | — | $ | 1 | $ | — | |||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Accumulated other comprehensive income (loss) | ||||||||||||||||||||
Net unrealized gain on cash flow hedges | $ | 488 | $ | 915 | $ | — | $ | — | $ | — | ||||||||||
Pension and non-pension postretirement benefit plans | (2,938 | ) | — | — | — | — | ||||||||||||||
Unrealized loss on marketable securities | — | — | (1 | ) | — | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total accumulated other comprehensive income (loss) | $ | (2,450 | ) | $ | 915 | $ | (1 | ) | $ | — | $ | — | ||||||||
|
|
|
|
|
|
|
|
|
|
17. Segment Information (Exelon, Generation, ComEd, PECO and BGE)
Exelon has nine reportable segments, ComEd, PECO, BGE and Generation’s six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and an aggregate of other regions not considered individually significant referred to collectively as “Other Regions”; including the South, West and Canada. Generation’s expanded number of reportable segments is the result of the acquisition of Constellation on March 12, 2012. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon evaluates the performance of ComEd, PECO and BGE based on net income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables provide information about accumulated OCI (loss) recorded (after tax) withinfoundation of Generation’s six reportable segments is based on the Consolidated Balance Sheetsgeographic location of its assets, and is largely representative of the Registrantsfootprints of an Independent System Operator (ISO) / Regional Transmission Operator (RTO) and/or North American Electric Reliability Corporation (NERC) region. Descriptions of each of Generation’s six reportable segments are as of September 30, 2011 and December 31, 2010:follows:
September 30, 2011 | Exelon | Generation | ComEd | PECO | ||||||||||||
Accumulated other comprehensive income (loss) | ||||||||||||||||
Net unrealized gain on cash flow hedges | $ | 145 | $ | 565 | $ | — | $ | — | ||||||||
Pension and non-pension postretirement benefit plans | (2,685 | ) | — | — | — | |||||||||||
Unrealized loss on marketable securities | — | — | (1 | ) | — | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total accumulated other comprehensive income (loss) | $ | (2,540 | ) | $ | 565 | $ | (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 | ) | $ | — | ||||||
|
|
|
|
|
|
|
|
• | Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina. |
15. Segment Information (Exelon,
• | Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the entire United States footprint of MISO, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky. |
• | New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. |
• | New York represents operations within New York ISO, which covers the state of New York in its entirety. |
• | ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas. |
• | Other Regions not considered individually significant: |
• | South represents operations in the Florida Reliability Coordinating Council (FRCC) and the remaining portions of the SERC Reliability Corporation (SERC) not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the Southwest Power Pool (SPP), covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas. |
• | West represents operations in the Western Electric Coordinating Council (WECC), which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota. |
• | Canada represents operations across the entire country of Canada and includes the Alberta Electric Systems Operator (AESO), Ontario Independent Electricity System Operator (OIESO) and the Canadian portion of MISO. |
Exelon and Generation ComEd and PECO)
Exelon has fivedo not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these regional reportable segments, which include Generation’s three reportable segments consisting of the Mid-Atlantic, Midwest, and South and West, and ComEd and PECO. ComEd and PECO each represent a single reportable segment; as such, no separate 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 their similar economic characteristics and the regulatory environments in which they operate.
segments. Exelon and Generation evaluate the performance of Generation’s power marketing activities in the Mid-Atlantic, Midwest, and South and West based on revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement of 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. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd, PECO and PECO.BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for internally generated energy and fuel costs associated with tolling agreements. Generation’s other business activities, including retail and wholesale gas, upstream natural gas, proprietary trading, compensation underenergy efficiency and demand response, the reliability-must-run rate schedule, other revenuesdesign, construction, and mark-to-market activities are not allocated to a region. Exelon and Generation do not use a measureoperation of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments. Exelon evaluates the performance of ComEd and PECO based on net income.renewable energy, heating, cooling,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, are not allocated to regions. Further, Generation’s compensation under the reliability-must-run rate schedule, results of operations from the clean-coal assets held for sale; Brandon Shores, Wagner, and C.P. Crane, and other miscellaneous revenues, mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger are also not allocated to a region.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30,March 31, 2012 and 2011 and 2010 is as follows:
Three Months Ended September 30, 2011 and 2010
Generation(a) | ComEd | PECO | Other | Intersegment Eliminations | Exelon | |||||||||||||||||||
Total revenues(b): | ||||||||||||||||||||||||
2011 | $ | 2,862 | $ | 1,784 | $ | 946 | $ | 206 | $ | (503 | ) | $ | 5,295 | |||||||||||
2010 | 2,655 | 1,918 | 1,495 | 183 | (960 | ) | 5,291 | |||||||||||||||||
Intersegment revenues(c): | ||||||||||||||||||||||||
2011 | $ | 304 | $ | 1 | $ | 2 | $ | 203 | $ | (503 | ) | $ | 7 | |||||||||||
2010 | 778 | — | 1 | 183 | (959 | ) | 3 | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||
2011 | $ | 386 | $ | 112 | $ | 105 | $ | (2 | ) | $ | — | $ | 601 | |||||||||||
2010 | 605 | 121 | 127 | (8 | ) | — | 845 | |||||||||||||||||
Total assets: | ||||||||||||||||||||||||
September 30, 2011 | $ | 26,086 | $ | 22,983 | $ | 9,336 | $ | 6,014 | $ | (10,263 | ) | $ | 54,156 | |||||||||||
December 31, 2010 | 24,534 | 21,652 | 8,985 | 6,651 | (9,582 | ) | 52,240 |
Generation(a) | ComEd | PECO | BGE(b) | Other(c) | Intersegment Eliminations | Exelon | ||||||||||||||||||||||
Total revenues(d): | ||||||||||||||||||||||||||||
2012 | $ | 2,739 | $ | 1,388 | $ | 875 | $ | 52 | $ | 351 | $ | (719 | ) | $ | 4,686 | |||||||||||||
2011 | 2,643 | 1,466 | 1,153 | 186 | (492 | ) | 4,956 | |||||||||||||||||||||
Intersegment revenues(e): | ||||||||||||||||||||||||||||
2012 | $ | 366 | $ | 1 | $ | 1 | $ | 1 | $ | 350 | $ | (719 | ) | $ | — | |||||||||||||
2011 | 306 | 1 | 1 | 186 | (493 | ) | 1 | |||||||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||||||
2012 | $ | 166 | $ | 87 | $ | 97 | $ | (65 | ) | $ | (85 | ) | $ | — | $ | 200 | ||||||||||||
2011 | 495 | 69 | 126 | (21 | ) | — | 669 | |||||||||||||||||||||
Total assets: | ||||||||||||||||||||||||||||
March 31, 2012 | $ | 41,723 | $ | 22,589 | $ | 9,215 | $ | 7,369 | $ | 10,876 | $ | (14,144 | ) | $ | 77,628 | |||||||||||||
December 31, 2011 | 27,433 | 22,638 | 9,156 | 6,162 | (10,394 | ) | 54,995 |
(a) | Generation |
(b) | Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through March 31, 2012. |
(c) | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. |
(d) | For the three months ended |
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 and West | Other(b) | Generation | ||||||||||||||||
Total revenues(a): |
| |||||||||||||||||||
2011 | $ | 1,020 | $ | 1,365 | $ | 384 | $ | 93 | $ | 2,862 | ||||||||||
2010 | 814 | 1,526 | 282 | 33 | 2,655 | |||||||||||||||
Revenues net of purchased power and fuel expense: | ||||||||||||||||||||
2011 | $ | 836 | $ | 853 | $ | 98 | $ | (37 | ) | $ | 1,750 | |||||||||
2010 | 564 | 1,044 | (11 | ) | 113 | 1,710 |
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2011 and 2010Generation total revenues:
Generation(a) | ComEd | PECO | Other | Intersegment Eliminations | Exelon | |||||||||||||||||||
Total revenues(b): |
| |||||||||||||||||||||||
2011 | $ | 8,147 | $ | 4,694 | $ | 2,942 | $ | 579 | $ | (1,429 | ) | $ | 14,933 | |||||||||||
2010 | 7,428 | 4,832 | 4,220 | 542 | (2,872 | ) | 14,150 | |||||||||||||||||
Intersegment revenues(c): | ||||||||||||||||||||||||
2011 | $ | 856 | $ | 2 | $ | 4 | $ | 576 | $ | (1,429 | ) | $ | 9 | |||||||||||
2010 | 2,330 | 1 | 4 | 542 | (2,871 | ) | 6 | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||
2011 | $ | 1,325 | $ | 295 | $ | 314 | $ | (45 | ) | $ | — | $ | 1,889 | |||||||||||
2010 | 1,548 | 246 | 303 | (58 | ) | — | 2,039 |
|
|
|
Mid-Atlantic | Midwest | South and West | Other(b) | Generation | ||||||||||||||||
Total revenues(a): |
| |||||||||||||||||||
2011 | $ | 3,069 | $ | 4,089 | $ | 676 | $ | 313 | $ | 8,147 | ||||||||||
2010 | 2,344 | 4,259 | 580 | 245 | 7,428 | |||||||||||||||
Revenues net of purchased power and fuel expense: | ||||||||||||||||||||
2011 | $ | 2,573 | $ | 2,704 | $ | 84 | $ | (237 | ) | $ | 5,124 | |||||||||
2010 | 1,760 | 3,054 | (102 | ) | 274 | 4,986 |
2012 | 2011 | |||||||||||||||||||||||
Revenues from external customers(a) | Intersegment revenues | Total Revenues | Revenues from external customers(a) | Intersegment revenues(b) | Total Revenues | |||||||||||||||||||
Mid-Atlantic | $ | 970 | $ | (4 | ) | $ | 966 | $ | 1,075 | $ | — | $ | 1,075 | |||||||||||
Midwest | 1,215 | 4 | 1,219 | 1,427 | — | 1,427 | ||||||||||||||||||
New England | 91 | 2 | 93 | 3 | — | 3 | ||||||||||||||||||
New York | 45 | (2 | ) | 43 | — | — | — | |||||||||||||||||
ERCOT | 128 | — | 128 | 101 | — | 101 | ||||||||||||||||||
Other Regions(c) | 75 | 4 | 79 | 37 | — | 37 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total Revenues for Reportable Segments | $ | 2,524 | $ | 4 | $ | 2,528 | $ | 2,643 | $ | — | $ | 2,643 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Other(d) | 215 | (4 | ) | 211 | — | — | — | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total Generation Consolidated Operating Revenues | $ | 2,739 | $ | — | $ | 2,739 | $ | 2,643 | $ | — | $ | 2,643 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
(a) | Includes all wholesale and retail electric sales |
(b) | There were no transactions among Generation’s reportable segments which would result in intersegment revenue for |
(c) | Other regions includes the South, West and Canada, which are not considered individually significant. |
(d) | Other represents activities not allocated to a region and includes retail and wholesale gas, upstream natural gas, proprietary trading, demand response, energy efficiency, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, mark-to-market activities associated with Generation’s economic hedging activities. In addition, includes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the merger date. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation total revenues net of purchased power and fuel expense:
2012 | 2011 | |||||||||||||||||||||||
RNF from external customers(a) | Intersegment RNF | Total RNF | RNF from external customers(a) | Intersegment RNF(b) | Total RNF | |||||||||||||||||||
Mid-Atlantic | $ | 774 | $ | (4 | ) | $ | 770 | $ | 914 | $ | — | $ | 914 | |||||||||||
Midwest | 813 | 4 | 817 | 965 | — | 965 | ||||||||||||||||||
New England | 37 | 2 | 39 | 2 | — | 2 | ||||||||||||||||||
New York | 10 | (2 | ) | 8 | — | — | — | |||||||||||||||||
ERCOT | 34 | — | 34 | 4 | — | 4 | ||||||||||||||||||
Other Regions(c) | 10 | 4 | 14 | (8 | ) | — | (8 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total Revenues net of purchased power and fuel expense for Reportable Segments | $ | 1,678 | $ | 4 | $ | 1,682 | $ | 1,877 | $ | — | $ | 1,877 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Other(d) | 17 | (4 | ) | 13 | (117 | ) | — | (117 | ) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total Generation Revenues net of purchased power and fuel expense | $ | 1,695 | $ | — | $ | 1,695 | $ | 1,760 | $ | — | $ | 1,760 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
(a) | Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. |
(b) |
|
(c) | Other regions includes the South, West and Canada, which are not considered individually significant. |
(d) | Other represents activities not allocated to a region and includes retail and wholesale gas, upstream natural gas, proprietary trading, |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Dollars in millions except per share data, unless otherwise noted)
Exelon, a utility services holding company, operates through the following principal subsidiaries:
• | Generation, whose business consists of |
• | ComEd, whose business consists of the purchase and regulated retail sale of electricity and the provision of |
• | PECO, whose business consists of the purchase and regulated retail sale of electricity and the provision of |
• | BGE, whose business consists of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore. |
Exelon has fivenine reportable segments consisting of the Mid-Atlantic,Generation’s six power marketing reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and South and Westother regions in Generation,Generation), ComEd, PECO and PECO.BGE. See Note 1517 of the Combined Notes to Consolidated Financial Statements for segment information.additional information regarding Exelon’s reportable segments.
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.
Exelon’s consolidated financial information includes the results of its four separate subsidiary registrants, Generation, ComEd, PECO and BGE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO and BGE. However, none of the Registrants makes any representation as to information related solely to Exelon or the separate subsidiary registrants of Exelon other than itself.
Financial Results. The following consolidated financial results reflect the results of Exelon for the three months ended March 31, 2012 compared to the same period in 2011. The 2012 financial results only include the operations of Constellation and BGE from the date of the merger with Constellation (“the Merger”), March 12, 2012, through March 31, 2012. All amounts presented below are before the impact of income taxes, except as noted.
Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010.
2012 | 2011 | Favorable (Unfavorable) Variance | ||||||||||||||||||||||||||||||
Generation | ComEd | PECO | BGE | Other | Exelon | Exelon | ||||||||||||||||||||||||||
Operating revenues | $ | 2,739 | $ | 1,388 | $ | 875 | $ | 52 | $ | (368 | ) | $ | 4,686 | $ | 4,956 | $ | (270 | ) | ||||||||||||||
Purchased power and fuel | 1,044 | 620 | 411 | 68 | (378 | ) | 1,765 | 2,001 | 236 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Revenue net of purchased power and fuel (a) | 1,695 | 768 | 464 | (16 | ) | 10 | 2,921 | 2,955 | (34 | ) | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Other operating expenses | ||||||||||||||||||||||||||||||||
Operating and maintenance | 1,175 | 318 | 203 | 60 | 208 | 1,964 | 1,223 | (741 | ) | |||||||||||||||||||||||
Depreciation and amortization | 153 | 149 | 53 | 19 | 8 | 382 | 327 | (55 | ) | |||||||||||||||||||||||
Taxes other than income | 73 | 75 | 31 | 9 | 6 | 194 | 203 | 9 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total other operating expenses | 1,401 | 542 | 287 | 88 | 222 | 2,540 | 1,753 | (787 | ) | |||||||||||||||||||||||
Equity in loss of unconsolidated affiliates | (22 | ) | — | — | — | — | (22 | ) | — | (22 | ) | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Operating income (loss) | 272 | 226 | 177 | (104 | ) | (212 | ) | 359 | 1,202 | (843 | ) | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Other income and deductions | ||||||||||||||||||||||||||||||||
Interest expense, net | (54 | ) | (82 | ) | (31 | ) | (8 | ) | (20 | ) | (195 | ) | (181 | ) | (14 | ) | ||||||||||||||||
Other, net | 178 | 4 | 2 | 1 | 9 | 194 | 94 | 100 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total other income and deductions | 124 | (78 | ) | (29 | ) | (7 | ) | (11 | ) | (1 | ) | (87 | ) | 86 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Income (loss) before income taxes | 396 | 148 | 148 | (111 | ) | (223 | ) | 358 | 1,115 | (757 | ) | |||||||||||||||||||||
Income taxes | 230 | 61 | 51 | (46 | ) | (138 | ) | 158 | 446 | 288 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net income (loss) | 166 | 87 | 97 | (65 | ) | (85 | ) | 200 | 669 | (469 | ) | |||||||||||||||||||||
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends | (2 | ) | — | 1 | 1 | — | — | 1 | 1 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net income (loss) on common stock | $ | 168 | $ | 87 | $ | 96 | $ | (66 | ) | $ | (85 | ) | $ | 200 | $ | 668 | $ | (468 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) | The Registrants’ evaluate operating performance using the measure of revenue net of purchased power and fuel expense. The Registrants’ believe 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. |
Exelon’s net income was $601$200 million for the three months ended September 30, 2011March 31, 2012 as compared to $845$668 million for the three months ended September 30, 2010,March 31, 2011, and diluted earnings per average common share were $0.90$0.28 for the three months ended September 30, 2011March 31, 2012 as compared to $1.27$1.01 for the three months ended September 30, 2010.March 31, 2011.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $202$34 million primarily related to a decrease in CTC recoveries at PECO of $351 million as a result of a $148 million decrease in the end ofMidwest and a $144 million decrease in 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 $91 million in 2011 from Generation’s hedging activities comparedMid-Atlantic both due to mark-to-market gains of $163 million in 2010 had an unfavorable impact on Generation’s operating results.lower capacity revenues, lower realized power prices and increased nuclear fuels costs. In addition, Generation’s operating revenue net of purchased power and fuel expense decreased by $191$122 million in the Midwest due to lower capacity revenues, lower realized power prices and increased nuclear fuel costs.the amortization of the acquired energy contract, net, recorded at fair value at the merger date. Offsetting these unfavorable impacts were increased operating revenuesmark-to-market gains of $71 million in 2012 from Generation’s hedging activities, net of intercompany eliminations, compared to $146 million in mark-to-market losses in 2011 and an increase of $97 million in the New England, New York, ERCOT and Other Regions primarily as a result of the Merger as these regions previously were not significant contributors to revenue net of purchased power and fuel expense at Generation of $272 million in the Mid-Atlantic due to increased realized margins on volumes previously sold under Generation’s PPA with PECO, which expired on December 31, 2010, and $109 million in the South and West at Generation primarily driven by favorable pricing as a result of extreme weather and market conditions that occurred in Texas in August 2011. Operating revenue net of purchase power expense and fuel expense at Generation was also impacted favorably by additional revenues from Exelon Wind, which was acquired in December 2010.Generation. ComEd’s and PECO’s operating revenues net of purchased power and fuel expense increased by $44$91 million and $31 million,
respectively, as a result of improved pricing primarily due to the newhigher electric distribution rates effective, June 1, 2011, pursuant to ComEd’s 2010 Rate Case order and new electric and natural gas distribution rates effective January 1, 2011 pursuant to PECO’s approved 2010 electric and natural gas distribution rate case settlements.
Operating and maintenance expense increased by $254 million primarily as a result of increased storm costs in the ComEd and PECO service territories of $67 million and $25 million, respectively, increased labor, other benefits, contracting and materials expenses of $46 million, including Exelon Wind, and the impacts of nuclear refueling outage costs, including the co-owned Salem plant, of $25 million at Generation. The increase was also attributable to a $28 million increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion and $29 million of costs related to the acquisitions of Wolf Hollow, Antelope Valley and the proposed merger with Constellation.
Depreciation and amortization expense decreased by $246 million primarily due to a decrease in CTC amortization expense at PECO of $281 millionrevenues resulting from the endreconciliation of the transition period on December 31, 2010, partially offset by increased depreciation expense primarily dueComEd’s distribution revenue requirement pursuant to additional plant placed in serviceEIMA. PECO’s and the acquisition of Exelon Wind. Exelon’s results were also significantly affected by unrealized losses on NDT funds of $141 million in 2011 (compared to unrealized gains of $107 million in 2010) for Non-Regulatory Agreement Units as a result of unfavorable market performance.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. Exelon’s net income was $1,889 million for the nine months ended September 30, 2011 as compared to $2,039 million for the nine months ended September 30, 2010, and diluted earnings per average common share were $2.84 for the nine months ended September 30, 2011 as compared to $3.08 for the nine months ended September 30, 2010.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $539 million primarily related to a decrease in CTC recoveries at PECO of $906 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 $363 million in 2011 from Generation’s hedging activities compared to $273 million in mark-to-market gains in 2010 also had an unfavorable impact on Generation’sBGE’s operating results. In addition, Generation’s operating revenuerevenues net of purchased power and fuel expense decreased by $350 million in the Midwest due to decreased realized margins in 2011 for volumes previously sold under the 2006 ComEd auction contracts, higher incurred congestion costs and increased nuclear fuel costs. Offsetting these unfavorable impacts were increased operating revenues net of purchased power and fuel expense at Generation of $813 million in the Mid-Atlantic due to increased realized margins on volumes previously sold under Generation’s PPA with PECO, which expired on December 31, 2010, and $186 million in the South and West primarily driven by the performance of Exelon’s generating units during extreme weather events that occurred in Texas in February and August 2011. Operating revenue net of purchased power and fuel expense in the South and West was also impacted favorably by additional revenues from Exelon Wind which was acquired in December 2010 and higher realized margins due to favorable market conditions. ComEd’s and PECO’s operating revenues net of purchased power and fuel expense increased by $57$56 million and $116$16 million, respectively, primarily as a result of improved pricing primarily due tounfavorable weather at PECO and the new electric distribution rates effective June 1, 2011 pursuant to ComEd’s 2010 Rate Case order and new electric and natural gas distribution rates effective January 1, 2011 pursuant to PECO’s 2010 approved electric and natural gas distributionaccrual of the residential customer rate case settlements.credit at BGE in connection with the Merger.
Operating and maintenance expense increased by $467$741 million primarily as a result of increased storm$216 million in costs incurred as part of the Maryland order approving the Merger and costs of $195 million associated with a settlement with the FERC in the ComEdMarch, 2012. The increase was also attributable to $145 million in transaction costs and PECO service territories of $72 million and $10 million, respectively, and a $55 million increase in uncollectible accounts expense at ComEd principally dueemployee-related expenses related to the impact of the recovery rider mechanism being approved by the ICCmerger, an increase in 2010. Exelon’s results were also affected by increased labor, other benefits, contracting and materials expenses of $157$87 million, including Exelon Wind. The increase was also attributable to a $35 millionand an increase in nuclear refueling outage costs, including the co-owned Salem plant, a $28 million increase in Generation’s decommissioning obligation for spent nuclear fuel at Zionpension and $54 million
OPEB expense of costs related to the acquisitions of Wolf Hollow, Antelope Valley and the proposed merger with Constellation. These impacts were partially offset by one-time net benefits of $32 million to re-establish 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.$31 million.
Depreciation and amortization expense decreasedincreased by $624$55 million primarily due to a decrease in CTC amortization expense at PECO of $725 millionhigher plant balances resulting from the endaddition of Constellation and BGE’s plant balances as well as ongoing capital expenditures at Generation, ComEd and PECO.
Equity in losses of unconsolidated affiliates was $22 million for the transition period on Decemberthree months ended March 31, 2010, partially offset by increased depreciation expense2012 due to the addition of Generation’s ownership interest in CENG in connection with the Merger. CENG recorded a loss primarily due to additional plant placed in service and the acquisition of Exelon Wind.planned nuclear refueling outage days from March 12, 2012 through March 31, 2012.
Interest expense decreasedincreased by $89$14 million primarily due to an increase in debt assumed in connection with the impact of 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 in 2010, respectively. In addition, in 2011,merger. Other, net at Exelon recorded interest income and tax benefits of $46 million, net of tax including the impact on the manufacturer’s deduction, due to the 2011 NDT fund special transfer tax deduction. The decrease in interest expense was partially offset by higher interest expense at Generation and ComEd due to higher outstanding debt balances. Exelon’s results were also significantly affected by unrealized losses on NDT funds of $88 million in 2011 (compared to unrealized gains of $48 million in 2010) for Non-Regulatory Agreement Unitsincreased as a result of unfavorable market performance.the contractual elimination of income tax expenses of $64 million in 2012 (compared to $27 million in 2011) associated with NDT funds of the Regulatory Agreement Units.
Exelon’s results for the ninethree months ended September 30, 2010March 31, 2012 were favorably affected by certain prior year income tax-related matters. In 2010,2012, Exelon recorded a $65$117 million (after-tax) charge(after tax) non-cash benefit to income tax expense as a result of health care legislation passeda change in March 2010 that includesstate deferred tax rates resulting from a provision that reducesreassessment of anticipated apportionment of Exelon’s deferred taxes due to the deductibility of retiree prescription drug benefits for Federal income tax purposes. This amount was partially offsetmerger. Exelon’s results were also favorably affected by a 2011 non-cash charge of $29 million (after-tax)(after tax) recorded at Exelon in 2011 for the remeasurement of deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation and for the updated long-term state tax apportionment.
For further detail regarding the financial results for the three and nine months ended September 30, 2011,March 31, 2012, 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 September 30, 2011March 31, 2012 were $743$603 million, or $1.12$0.85 per diluted share, compared with adjusted (non-GAAP) operating earnings of $739$778 million, or $1.11$1.17 per diluted share, for the same period in 2010. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 2011 were $2,219 million, or $3.34 per diluted share, compared with adjusted (non-GAAP) operating earnings of $2,057 million, or $3.10 per diluted share, for the same period in 2010.2011. 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. 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.
The following table provides a reconciliation between net income as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2011March 31, 2012 as compared to the same periodsperiod in 2010:2011:
Three Months Ended September 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
(All amounts after tax) | Earnings per Diluted Share | Earnings per Diluted Share | ||||||||||||||
Net Income | $ | 601 | $ | 0.90 | $ | 845 | $ | 1.27 | ||||||||
Illinois Settlement Legislation(a) | — | — | 3 | — | ||||||||||||
Mark-to-Market Impact of Economic Hedging Activities(b) | 55 | 0.08 | (99 | ) | (0.14 | ) | ||||||||||
Unrealized (Gains) Losses Related to NDT Fund | 76 | 0.12 | (60 | ) | (0.09 | ) | ||||||||||
Impairment of Certain Emission Allowances(d) | — | — | 35 | 0.05 | ||||||||||||
Retirement of Fossil Generating Units(e) | 2 | — | 14 | 0.02 | ||||||||||||
Asset Retirement Obligation(f) | 16 | 0.02 | — | — | ||||||||||||
Constellation Acquisition Costs(g) | 11 | 0.02 | — | — | ||||||||||||
Acquisition Costs(h) | 5 | 0.01 | 1 | — | ||||||||||||
Wolf Hollow acquisition(i) | (23 | ) | (0.03 | ) | — | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Adjusted (non-GAAP) Operating Earnings | $ | 743 | $ | 1.12 | $ | 739 | $ | 1.11 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Nine Months Ended September 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
(All amounts after tax) | Earnings per Diluted Share | Earnings per Diluted Share | ||||||||||||||
Net Income | $ | 1,889 | $ | 2.84 | $ | 2,039 | $ | 3.08 | ||||||||
Illinois Settlement Legislation(a) | — | — | 10 | 0.01 | ||||||||||||
Mark-to-Market Impact of Economic Hedging Activities(b) | 219 | 0.34 | (166 | ) | (0.25 | ) | ||||||||||
Unrealized (Gains) Losses Related to NDT Fund | 46 | 0.07 | (28 | ) | (0.04 | ) | ||||||||||
Impairment of Certain Emission Allowances(d) | — | — | 35 | 0.05 | ||||||||||||
Retirement of Fossil Generating Units(e) | 29 | 0.04 | 34 | 0.05 | ||||||||||||
Asset Retirement Obligation(f) | 16 | 0.02 | — | — | ||||||||||||
Constellation Acquisition Costs(g) | 26 | 0.04 | — | — | ||||||||||||
Acquisition Costs(h) | 5 | 0.01 | 1 | — | ||||||||||||
Wolf Hollow acquisition(i) | (23 | ) | (0.03 | ) | — | — | ||||||||||
City of Chicago Settlement with ComEd(j) | — | — | 2 | — | ||||||||||||
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes(k) | — | — | 65 | 0.10 | ||||||||||||
Non-Cash Charge Resulting From Health Care Legislation(l) | — | — | 65 | 0.10 | ||||||||||||
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation(m) | 29 | 0.04 | — | — | ||||||||||||
Recovery of Costs Resulting From Distribution Rate Case | (17 | ) | (0.03 | ) | — | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Adjusted (non-GAAP) Operating Earnings | $ | 2,219 | $ | 3.34 | $ | 2,057 | $ | 3.10 | ||||||||
|
|
|
|
|
|
|
|
Three Months Ended March 31, | ||||||||||||||||
2012 | 2011 | |||||||||||||||
(All amounts after tax) | Earnings per Diluted Share | Earnings per Diluted Share | ||||||||||||||
Net Income | $ | 200 | $ | 0.28 | $ | 668 | $ | 1.01 | ||||||||
Mark-to-Market Impact of Economic Hedging | ||||||||||||||||
Activities (a) | (43 | ) | (0.06 | ) | 89 | 0.14 | ||||||||||
Unrealized Gains Related to NDT Fund | ||||||||||||||||
Investments (b) | (36 | ) | (0.05 | ) | (24 | ) | (0.04 | ) | ||||||||
Retirement of Fossil Generating Units (c) | 4 | 0.01 | 16 | 0.02 | ||||||||||||
Constellation Merger and Integration Costs (d) | 113 | 0.16 | — | — | ||||||||||||
Maryland Commitments (e) | 227 | 0.32 | — | — | ||||||||||||
Amortization of Acquired Contracts (f) | 78 | 0.11 | — | — | ||||||||||||
FERC Settlement (g) | 172 | 0.25 | — | — | ||||||||||||
Plant Divestitures (h) | 2 | — | — | — | ||||||||||||
Non-Cash Benefit Resulting from Reassessment of State Deferred Income Taxes (i) | (117 | ) | (0.17 | ) | — | — | ||||||||||
Other Acquisition Costs (j) | 3 | — | — | — | ||||||||||||
Non-Cash Charge Resulting from Illinois Tax | ||||||||||||||||
Rate Change Legislation (k) - | — | — | 29 | 0.04 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Adjusted (non-GAAP) Operating Earnings | $ | 603 | $ | 0.85 | $ | 778 | $ | 1.17 | ||||||||
|
|
|
|
|
|
|
|
(a) |
|
Reflects the impact of (gains) losses for the three |
|
Reflects the impact of (gains) |
|
Primarily reflects accelerated depreciation expense for the three |
|
Reflects certain costs incurred for the three |
(e) | Reflects costs incurred for the three months ended March 31, 2012 (net of taxes of $101 million) as part of the Maryland order approving the merger transaction. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information. |
(f) | Reflects the non-cash impact for the three months ended March 31, 2012 (net of taxes of $51 million) of amortization of acquired energy contracts recorded at fair value at the merger date. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information. |
(g) | Reflects costs incurred for the three months ended March 31, 2012 (net of taxes of $23 million) as part of a settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions. See Note 15 of the Combined Notes to Consolidated Financial Statements for additional information. |
(h) | Reflects |
(i) | Reflects a one-time, non-cash |
|
|
|
Reflects certain costs incurred for the three months ended March 31, 2012 associated with various acquisitions (net of taxes of $2 million). |
(k) | Reflects a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation. See Note |
|
Outlook for the Remainder of 20112012 and BeyondBeyond.
AcquisitionsMerger with Constellation
Proposed Acquisition of Constellation Energy Company. On April 28, 2011,March 12, 2012, the 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. Underwas completed. On the merger agreement,date, Constellation’s shareholders will receivereceived 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock. Based on Exelon’s closingopening share price on April 27, 2011,March 12, 2012, Constellation shareholders would receive $7.9and equity award holders received $7.4 billion in total equity value. The resulting company will retain the Exelon name and be headquartered in Chicago.
TheExelon has incurred and will continue to incur costs associated with evaluating, structuring and executing the merger transaction mustitself, meeting the various commitments set forth by regulators and agreed-upon with other interested parties as part of the merger approval process, and integrating the former Constellation businesses into Exelon.
For the three months ended March 31, 2012, expense has been recognized for costs incurred to achieve the merger as follows:
Pre-tax Expense | ||||||||||||||||||||
Three Months Ended March 31, 2012 | ||||||||||||||||||||
Merger and Integration Costs: | Generation (a) | ComEd | PECO | BGE (a) | Exelon (a) | |||||||||||||||
Transaction (b) | $ | — | $ | — | $ | — | $ | — | $ | 50 | ||||||||||
Maryland Commitments | 35 | — | — | 139 | 328 | |||||||||||||||
Employee-Related (c) | 47 | — | 5 | — | 58 | |||||||||||||||
Other (d) | 28 | 2 | 2 | 1 | 36 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | $ | 110 | $ | 2 | $ | 7 | $ | 140 | $ | 472 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(a) | For Exelon, Generation and BGE, includes the operations of the acquired businesses from the date of the merger, March 12, 2012, through March 31, 2012. |
(b) | External, third-party costs paid to advisors, consultants, lawyers and other experts to assist in the due diligence and regulatory approval processes and in the closing of the transaction. |
(c) | Costs primarily for employee severance and retention. ComEd and BGE established a regulatory asset of $11 million and $16 million, respectively, for severance benefits costs which are expected to be recovered over a five-year period. These costs are not included in the table above. |
(d) | Costs to integrate Constellation processes and systems into Exelon and to terminate certain Constellation debt agreements. |
Exelon projects incurring total additional merger-related costs, primarily in 2012 and 2013, of approximately $400 million, of which approximately $300 million is expected to be approvedrecognized as expense, and approximately $100 million is expected to be capitalized in connection with the integration of systems.
In addition, pursuant to conditions set forth by the shareholdersMDPSC in its approval of both the merger transaction, Generation expects to incur capital expenditures of $95 million to $120 million for the requirement to cause construction of a headquarters building in Baltimore for its competitive energy businesses (expected to be completed in 2 to 3 years) and up to $625 million for development of 285-300 MW of new electric generation facilities in Maryland (expected to be completed over the next ten years). The accounting treatment for the requirement to cause construction of the headquarters building in Baltimore may vary depending on the structure of the transaction.
Exelon and Constellation. Completion of the transaction isConstellation have also conditioned upon approval by the FERC, NRC, Maryland Public Service Commission
(MDPSC), the New York Public Service Commission (NYPSC), the Public Utility Commission of Texas (PUCT), and other state and federal regulatory bodies. The companies have proposedagreed to divestenter into contracts to sell three Constellation generating stations located in PJM which is the only market where there is a material overlap of generation ownedwithin 150 days (unless extended 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 October 2011, Exelon and Constellation reached a settlement with the PJM Independent Market Monitor, who had previously raised market power concerns regarding the merger. The settlement contains a number of commitments by the merged company, including limiting the universe of potential buyers of the divested assets to entities without significant market shares in the relevant PJM markets. The settlement also includes assurances about how the merged company will bid its units into the PJM markets. 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 FTC and/or the Antitrust Division of the DOJ and until specified waiting period requirements have expired. During the second quarter, Exelon and Constellation filed applications with FERC, the MDPSC, the NYPSC and the PUCT 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. During the third quarter, Exelon and Constellation received approval of the transaction from the PUCT.
Exelon was 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. Similar suits were also filed in the United States District Court for the District of Maryland. The suits sought to enjoin a Constellation shareholder vote on the proposed merger until all material information is disclosed and sought rescission of the proposed merger. During the third quarter, the parties to the suits reached an agreement in principle to settle the suits through additional disclosures to Constellation shareholders. The settlement is subject to court approval.
Through September 30, 2011, Exelon has incurred approximately $37 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 to be incurred 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 ofDOJ) following the merger by MDPSC, Exeloncompletion 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 will result 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 feecomplete the divestitures within 30 days after receipt of $800 million in the case of a termination fee payable by Exelon to Constellation or 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 Antelope Valley Solar Ranch One. On September 30, 2011, Generation announced its acquisition of Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar photovoltaic (PV) project under development in northern Los Angeles County, California, from First Solar, which developed and will build, operate, and maintain the project. Construction has started, with the first portionregulatory approvals. See Note 3 of the site expectedCombined Notes to come online in late 2012 and full operation plannedConsolidated Financial Statements for late 2013. When fully operational, Antelope Valley will be one of the largest PV solar projects in the world, with approximately 3.8 million solar panels generating enough clean, renewable electricity to power the equivalent of 75,000 average homes per year. The acquisition buildsadditional information on the Exelon commitment to clean energy as part of Exelon 2020, a businessmerger and environmental strategy to eliminate the equivalent of Exelon’s 2001 carbon footprint. The project has a 25-year PPA, approved by the
California Public Utilities Commission, with Pacific Gas & Electric Company“EXELON CORPORATION — Executive Overview,” for the full output of the plant. Exelon expects to invest up to $713 million in equity in the project through 2013. The DOE’s Loan Programs Office issued a loan guarantee of up to $646 million to support project financing for Antelope Valley. Exelon expects the total investment of up to $1.36 billion to be accretive to earnings beginning in 2013 and cash flow accretive starting in 2013. The project is value accretive, and will have stable earnings and cash flow profiles due to the PPA.
Acquisition of Wolf Hollow Generating Station. On August 24, 2011, Generation completed the acquisition of the equity interest of Wolf Hollow, LLC (Wolf Hollow), a combined-cycle natural gas-fired power plant in north Texas, pursuant to which Generation added 720 MWs of capacity within the ERCOT power market. The acquisition buildsmore information on the Exelon commitment to clean energy as parttreatment of Exelon 2020. Generation recognized a $36 million bargain purchase gain (i.e., negative goodwill) as part of the transaction. The gain was included within other, netsuch merger and integration costs in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. In connection with the acquisition, Generation terminated and settled its long-term PPA with Wolf Hollow; resulting in a gain of approximately $6 million, which is included within Operating Revenues (Other Revenue) in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
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,our non-GAAP 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 $16 million was paid during third quarter of 2011. As a result, total consideration recorded for the Exelon Wind acquisition was $925 million. The acquisition currently provides incremental earnings, provides cash flows starting in 2013 and is a key part of Exelon 2020.earnings.
Recent Natural Disasters, including the Japan Earthquake and Tsunami and the Industry’s Response
Generation’s fleet of nuclear power plants could be impacted by natural disasters, such as seismic activity, more frequent and more extreme weather events, changes in temperature and precipitation patterns, sea level rise and other related phenomena. Generation continuously assesses the impact such activity has, or could have, on its nuclear fleet to mitigate risks to public safety and plant operations. An example of such an event was theOn March 11, 2011, Japan experienced a 9.0 magnitude earthquake and ensuing tsunami experienced by Japan on March 11, 2011, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co. Also, on August 23, 2011, Generation’s fleet of nuclear plants throughout the Mid-Atlantic region of the United States experienced a 5.8 magnitude earthquake and continued to operate with no impact. Finally, during the third quarter of 2011, the Mid-Atlantic region of the United States experienced flooding associated with Hurricane Irene and tropical storm Lee. These events increase the risk to Generation that the NRC (Commission) or other regulatory or legislative bodies may change the laws or regulations governing, among other things, operations, maintenance, licensed 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 significant earthquake zones or in regions where tsunamis are a threat. Generation believes its nuclear generating facilities are able to shut down safely 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. Prior to the earthquake and tsunami in Japan, the NRC and licensees had been evaluating seismic risk in relation to the design basis and whether additional regulatory action was required. Following the March 11, 2011 events, interest in seismic risk intensified. On September 1, 2011, the NRC issued a draft generic letter that will, if finalized, require Generation to use a specified methodology to evaluate each of its plants for the current risk presented by seismic events and provide information to the NRC so that the NRC can determine whether additional regulatory action is required.
The NRC received petitions from various individuals and citizen groups requesting actions be taken in response to the events in Japan. A consortium of various citizen groups filed a petition with the NRC requesting that it 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. On September 9, 2011, the Commission denied the request. Also, various NRC petitions have been filed seeking suspension of all Boiling Water Reactor (BWR) Mark I operating licenses or other enforcement action until certain specified conditions are met. Another petition requests that the NRC take enforcement action by requiring all operating licensees of BWR Mark I and Mark II containments to demonstrate compliance with current regulatory requirements. These petitions could affect Dresden, Quad Cities, Oyster Creek and Peach Bottom stations (Mark I containment designs) and LaSalle and Limerick stations (Mark II containment designs). Generation does not believe the petitions will be successful. On May 18, 2011, the U.S. Court of Appeals of the Third Circuit 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 ishas already takingtaken 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, confirmation of event response procedures and readiness to protect the spent fuel pool, and verification of current qualifications of operators and support staff needed to implement the procedures. Generation is currently working onhas been addressing additional actions requested by INPO for improving and maintaining core and spent fuel pool cooling during an extended loss of power for at least 24 hours.
In April 2011, the NRC named six senior managers and staff to its task force for examining the agency’s regulatory requirements, programs, processes, and implementation in light of information from the Fukushima Daiichi site in Japan, following the March 11 earthquake and tsunami (Task Force). 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 to be taken in the near and longer term. 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 and do not present an imminent risk to public health and safety. 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. On August 19, 2011, the NRC directed the NRC staff to, among other things, identify those Task Force recommendations to be taken in the near term, prioritize and propose a schedule for all of the recommendations, propose regulatory actions to implement the recommendations, and identify additional recommendations. The Commission specifically called out the Task Force recommendation pertaining to the regulatory framework as being on an independent track for consideration over an eighteen month period.
On September 9, 2011, the NRC staff issued its report identifying seven Task Force recommendations to be taken in the near term or “without unnecessary delay.” The seven near term recommendations cover seismic and flooding risks, coping with extended loss of power in a station blackout, protecting and increasing the amount of backup equipment, reliable hardened vents for Mark I containment, and enhancing procedures to address severe accidents and emergency planning. On October 3, 2011, the NRC staff issued its recommendations for prioritizing and implementing the near term and remaining Task Force recommendations and an implementation schedule. Of note, the NRC staff confirmed in both the September 9, 2011 and October 3, 2011 reports the Task
Force’s conclusions that none of the findings or recommendations arising from the Task Force review presented an imminent risk to public health and safety. The NRC staff evaluated the potential and relative safety enhancements to be realized by each recommendation and, based on that evaluation, classified the recommendations as falling in three tiers: Tier 1, reflecting the near term recommendations to be initiated without unnecessary delay; Tier 2, reflecting recommendations to be deferred pending receipt of additional information, completion of Tier 1 activities, or the availability of resources; and Tier 3, reflecting recommendations to be deferred pending an additional nine month review by the NRC staff. With respect to the near term recommendations falling in Tier 1, the NRC staff added in the October 3, 2011 report recommendations for reliable hardened vents for Mark II containment and enhancements to spent fuel instrumentation as additional near term actions. As instructed by the Commission, the NRC staff also identified additional issues not considered by the Task Force that may, in the staff’s assessment, warrant regulatory action. Among the additional issues identified is the transfer of spent fuel to dry cask storage. The staff committed to provide an update on its evaluation of the additional issues within nine months. For each of the recommendations and additional issues, the NRC staff’s proposed schedule provides for stakeholder input prior to taking regulatory action.
On October 20, 2011, the NRC published the Commission’s votes and staff requirements memorandum approving the staff’s September 9, 2011 proposed actions to implement seven Task Force recommendations as near term actions, subject to a number of conditions. Specifically, the Commission encouraged the staff to create requirements based on a performance-based system which allows for flexible approaches and the ability to address a diverse range of site-specific circumstances and conditions and “strive to complete and implement the lessons learned from the Fukushima accident within five years — by 2016.” In addition, the Commission is scheduled in the near term to vote on the NRC staff’s October 3, 2011 report proposing a prioritization and implementation plan for the near term and remaining recommendations and issue instructions to the NRC staff for carrying out the decision of the Commission.
Generation is assessing the impacts of the NRC staff’s evaluations and the Commission’s approval of the recommendations for near term actions, both from an operational and a financial impact standpoint. Until the Commission votes on the NRC staff’s proposal for prioritizing and implementing the Task Force recommendations and the specific requirements for each recommendation are established after obtaining stakeholder input, Generation is unable to determine with specificity 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 the 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 noted above,During the fourth quarter
of 2011, the NRC staff identifiedissued its recommendations for prioritizing and implementing the transferTask Force recommendations and an implementation schedule which was approved by the Commission subject to a number of conditions. The NRC staff confirmed the Task Force’s conclusions that none of the findings arising from the Task Force review presented an imminent risk to public health and safety.
In March 2012, the Commission authorized its staff to issue three immediately effective orders to commercial reactor licensees operating in the United States for compliance no later than December 31, 2016. In summary, the orders require licensees: (1) to provide sufficient onsite portable equipment and resources to maintain or restore cooling capabilities for the containment, core, and spent fuel pool until offsite equipment is available and have offsite equipment and resources available to dry cask storage as an additional issuesustain cooling functions indefinitely; (2) to be evaluatedimprove the venting systems with boiling water reactor Mark I or Mark II containments (or for the Mark II plants, install new systems) that help prevent or mitigate core damage in the event of a serious accident by making the systems accessible and operable in the event of a prolonged station blackout and inadequate cooling; and (3) to install instrumentation to provide a reliable indication of water level in the spent fuel pool.
Additionally, the NRC staff overhas issued a nine month period.detailed information request to every operating commercial nuclear power plant in the United States. The facts surrounding what happened at the Fukushima Daiichi Nuclear Power Station, including the nature and extent of damages, the underlying causesinformation requested requires: (1) use of the situation,current NRC guidance to reevaluate current seismic and flood risk hazards against the degreedesign basis and provide a plan of actions to which these factors applyaddress vulnerabilities, including risks exceeding the design basis; (2) perform walk downs to Generation’s nuclear generating facilities, are still under investigation,ensure the ability to respond to seismic and will be for some time. Although the NRC staff’s September 9, 2011external flooding events and October 3, 2011 reports to the Commission and the Commission’s approval of the near term recommendations and instructionsprovide a corrective action plan to the NRC to address deficiencies; and (3) assess the means to provide power for communications equipment during a severe natural event and identify staffing required to implement the emergency plan for an event affecting all units with an extended loss of alternating current power and impeded access to the site.
The NRC staff provide clarityhas scheduled a number of meetings to obtain stakeholder input on implementation guidance for the orders and information requests. Generation is assessing the impacts of the orders and information requests and will continue monitoring the additional recommendations under review by the Staff, both from an operational and a financial impact standpoint. A comprehensive review of the NRC Tier 1 orders and information requests, as well as preliminary engineering assumptions and analysis, indicate that the financial impact of compliance is not anticipated to be significant to Generation’s financial position, results of operations, or cash flows over the next five years (required implementation deadline of December 31, 2016). However, until the specific requirements and guidance for each order, request for information, and recommendation are established after obtaining stakeholder input, Generation is unable to determine with specificity the impact the recommendations may have on its nuclear units. Additionally, Generation’s current assessments are specific to the Tier 1 recommendations and information requests as the NRC has not taken action with respect to issues that will be subject to regulatory reviewthe Tier 2 and action, the nature and degree of actions that will be required of Generation are still unknown and will be determined through the
regulatory process after allowing for stakeholder input. As a result,Tier 3 recommendations. Exelon and Generation are unable to conclude at this time to what extent any actions to comply with the requirements of Tier 2 and Tier 3 will impact their future financial position, results of operations, financial positions and cash flows. Generation will continue to engage in nuclear industry assessments and actions and stakeholder input. See ITEM 1A. RISK FACTORS of the 2010Exelon 2011 Form 10-K Item 1A. Risk Factors, for further discussion of the risk factors.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 to monitor NRC directives and guidance that may impact the uprates and, as it has in the past, 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 and retail 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,obtain for their output, (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)CSAPR and the New Jersey capacity legislation.MATS. SeeEnvironmental Matters andRegulatory and Legislative Matters sectionssection below for further detail on CSAPR and New Jersey capacity legislation, respectively.the MATS.
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues.
The market price for electricity is also affected by changes in the demand for electricity. Poor economic conditions, milder than normal weather, unexpected or unusual weather patterns and the growth of energy efficiency and demand 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 and/or capacity. The continued sluggish economy in the United States has led to slower growth ofa decline in demand for electricity. Based on yearComEd is projecting load demand to date load performance atremain essentially flat in 2012 compared to 2011, while PECO is projecting a decline of 3.9% in 2012 compared to 2011 as a result of the above drivers in addition to the anticipated closing of three oil refineries in its service territory.
Since September 30, 2011, forward natural gas prices for 2013 and 2014 have declined significantly; reflecting an increase in supply due to strong natural gas production (due to Shale gas development) and significantly warmer than normal weather so far this winter, as well as generally lowered expectations for gas demand and economic growth rates. Wholesale power prices have likewise decreased in response in part to the fourth quarter, ComEdlower gas prices, and PECO are projecting a slight decline in load demand forto the late December 2011 compared to 2010.judicial stay of the EPA’s CSAPR and various other market factors.
In addition, the Registrants haveExelon also has exposure to worldwide financial markets, including Europe.markets. The ongoing European debt crisis has contributed to the instability in global credit markets. Further disruptions in the European markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of September 30, 2011,March 31, 2012, approximately 35%44%, or $2.7$5.0 billion, of the Registrants’ available credit facilities were with European banks. The credit facilities include $7.7$11.4 billion in aggregate total commitments of which $6.9$8.5 billion was available as of September 30, 2011.March 31, 2012. There were no borrowings under the Registrants’ credit facilities as of September 30, 2011.March 31, 2012. See Note 78 of the Combined Notes to the Consolidated Financial Statements for additional information on the credit facilities.
Exelon routinely reviews its hedging policy, operating and capital costs, capital spending plans, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades. Based on the results of these assessments, Exelon management believes it is able to respond to changing market conditions in a manner that ensures reliable and safe service for Exelon’s customers and sufficient liquidity to operate Exelon’s businesses.
Hedging Strategy. Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact 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 growth 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 the remainder of 20112012 and 2012.2013. 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 three-year periods, which is intended to reduce the three years leading to the spot market.near-term financial impact of market price volatility. As of September 30, 2011,
March 31, 2012, the percentage of expected generation hedged was 97%-100%95%-98%, 85%-88%,68%-71% and 56%-59%40%-43% for the remainder of 2011, 2012, 2013 and 2013,2014, 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 57%55% 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 has announced a series of planned power uprates across its nuclear fleet that would result in between 1,175 and 1,300 and 1,500 MWs of additional generation capacity within eight years at a total investmentan overnight cost of approximately $3.65$3.3 billion in overnight cost, as measured in 2010 dollars.2012 dollars, of which approximately $850 million has been spent through March 31, 2012. Overnight costs do not include financing costs or cost escalation. As part of periodic reviews of the continued economic viability of the projects, conducted in the second quarter of 2011, 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 70%75% of the planned uprate MWs, are underway at the Limerick, TMI and Peach Bottom nuclear stations in Pennsylvania and the Byron, Braidwood, Dresden, LaSalle and Quad Cities plants in Illinois. The remaining uprate MWs will come from additional projects across Generation’s nuclear fleet beginning later in 20112012 and ending in 2017. At 1,300 nuclear-generated MWs, the uprates would displace 6 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 projected sources and uses of funds, 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 September 30, 2011,March 31, 2012, Generation has added 189250 MWs of nuclear generation through its uprate program, with another 1182 MWs scheduled to be added during the remainder of 2011.2012.
Transmission Development Project. Generation Renewable Development.Exelon, Electric Transmission America, LLC (ETA) and AEP Transmission Holding Company, LLC (AEP) Generation plans to construct multiple wind facilities in 2012, resulting in approximately 400 MWs of additional renewable generation. Total costs for the facilities are working collaboratively to develop a 420-mile extra high-voltage transmission project from the western Ohio border through Indiana to the northern portion of Illinois. Referred to as the Reliability Interregional Transmission Extension (RITE) Line project, the project is expected to strengthen the high-voltage transmission system and improve overall system reliability. RITELine Illinois, LLC (RITELine Illinois) and RITELine Indiana, LLC (RITELine Indiana) have been formed as project companies to develop and own the project. RITELine Illinois will own the transmission assets located in Illinois and is owned 75% by ComEd and 25% by RITELine Transmission Development Company, LLC (RTD). RITELine Indiana will own the transmission assets located in Indiana and is owned by ETA (37.5%), AEP (37.5%) and RTD (25%). Exelon Transmission Company, LLC and ETA each own 50% of RTD. The total cost of the RITE Line project is expected to be approximately $1.6 billion, with$720 million. Total costs incurred through March 31, 2012 were approximately $200 million. Upon completion of these wind facilities, Generation will have approximately 1,300 MW of wind capacity within its portfolio of generating assets.
Generation is currently constructing a solar PV facility in Los Angeles County, California. The facility is expected to become operational during the Illinois portionfirst quarter of 2013. Upon completion, the facility will add 230 MWs to Generation’s renewable generation fleet. Total costs for the facility are expected to be approximately $1.4 billion. Total costs incurred through March 31, 2012 were approximately $160 million. See Note 3 of the line expectedCombined Notes to cost approximately $1.2 billion. The ultimate costConsolidated Financial Statements for additional information.
Utility Infrastructure. During the fourth quarter of 2011, EIMA was enacted in Illinois, which provides for ComEd to invest an additional $2.6 billion over a ten-year period, beginning in 2012, to modernize Illinois’ electric utility infrastructure and for greater certainty related to the line will depend onrecovery of costs by a number of factors, including RTO requirements, state siting requirements, routing of the line, and equipment and commodity costs. The project will be built in stages over three to four years, likely between 2015 and 2018, and is subject to FERC, PJM and state approvals. Significant funding for this project is not expected to occur until 2014, with most of the funding expected in 2015-2017.
On July 18, 2011, RITELine Illinois and RITELine Indiana filed at FERC for incentive rates andutility through a pre-established distribution formula rate for the RITE Line project. On October 14, 2011, FERC issued an order on the incentive and formula rate filing. The order grants a base rate of return on common equity of 9.93%, plus a 50 basis point adder for the project being in an RTO and a 100 basis point adder for the risks and challenges of the project, resulting in a total rate of return on common equity of 11.43%. The order grants a hypothetical capital structure of 45% debt and 55% equity until any part of the project enters commercial operations. The order also grants 100% recovery for construction work in progress, 100% recovery for abandonment, if the line is abandoned through no fault of the RITELine developers, and the ability to treat pre-construction costs as a regulatory asset. All incentives, including the abandonment incentive, are contingent on inclusion of the project in the PJM RTEP. The order is subject to petitions for rehearing.tariff.
Advanced Metering Infrastructure.In April 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan, under which PECO will deploy 600,000 smart meters within three years and deploy smart meters to allrepresenting an investment of its electric customers over the next 10 years. Also in April 2010, PECO entered into a Financial Assistance Agreement with the DOE for a $200 million award for SGIG funds under the ARRA. In total, through 2020, PECO plans to spend up to a total of $650 million, including its $200 million SGIG, on its smart grid and smart meter infrastructure. The $200
In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million SGIGresidential and commercial electric and gas smart meters at an expected total cost of approximately $480 million. Under a grant from the DOE, BGE is being useda recipient of $200 million in federal funding for smart grid and other related initiatives. This grant allows BGE to reducebe reimbursed for smart grid and other related expenditures up to $200 million, substantially reducing the impacttotal cost of these investments on PECO ratepayers.
On April 15, 2011,initiatives. See 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 operational in June 2010. As of September 30, 2011, ComEd had spent $77 million associated with the pilot 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 lower energy bills. Due to an adverse September 30, 2010 Illinois Appellate Court decision, ComEd faced certain cost recovery issues in connection with the pilot program. The ICC order in ComEd’s 2010 Rate Case subsequently approved base rate recovery of the investment and pilot program costs. See Regulatory and Legislative Matters section below and Note 34 of the Combined Notes to Consolidated Financial Statements for additional information on cost recovery issues related to ComEd’s AMI pilot program.the utility infrastructure projects.
Liquidity and Cost Management
Pension Plan Funding. As a result of accelerated cash benefits associated with the Tax Relief Act of 2010, Exelon contributed $2.1 billion to its pension plans in January 2011, representing substantially 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 83% at December 31, 2011, subject to 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.
On September 7, 2011, ComEd issued $250 million of 1.95% First Mortgage Bonds due September 1, 2016 and $350 million of 3.40% First Mortgage Bonds due September 1, 2021. A portion of the net proceeds of the bonds was used to refinance $191 million of ComEd’s variable rate tax-exempt bonds on October 12, 2011. The remainder of the net proceeds will be used to refinance $345 million of 5.40% First Mortgage bonds due December 15, 2011 and to fund other general corporate purposes.
Credit Facilities. On March 23, 2011, Exelon Corporate, Generation, PECO and PECO replaced theirBGE have unsecured revolving credit facilities with new facilities with aggregate bank commitments of $500 million, $5.3$3.6 billion, $5.6 billion, $0.6 billion and $600 million,$0.6 billion, respectively. Although the covenants are largely the same as the priorThe Registrants’ revolving credit facilities the newexpire between October 2013 and March 2016. The supplemental facilities at Exelon and Generation 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.expirations that range from September 2013 through March 2016.
ComEd’s $1.0 billionOn March 28, 2012, ComEd replaced its unsecured revolving credit facility with a new facility with aggregate bank commitments of $1.0 billion. The new facility expires onin March 25, 20132017, unless extended in accordance with terms. ComEd plans to renew or replace the credit facility in 2012.agreement. See Note 78 of the Combined Notes to Consolidated Financial Statements for further information regarding the credit facility terms.
On October 21, 2011, Generation, ComEd and PECO replaced their expiring minority and community bank credit facility agreements with new minority and community bank credit facility agreements in the amounts of $50 million, $34 million and $34 million, respectively. See Note 7Exelon expects lower liquidity requirements as a result of the Combined Notesmerger due to Consolidated Financial Statements for further information regarding the credit facilities.matching of load and generation.
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. Exelon is committed to maintaining a cost control focus and continues to analyze cost trends to identify future cost savings opportunities and implement more planning and performance-measurement tools to 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 overall 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 benefit from the long-term positive impact of the requirements on capacity and energy prices while minimizing the impact of costs of compliance on Exelon’s operations, cash flows or financial position.
Environmental Legislative and Regulatory Developments
Exelon supports the promulgation of environmental regulation by the U.S. EPA, including air, water and waste controls for electric generating units. See discussion below for further details. The air and waste regulations will have a disproportionate adverse impact on fossil-fuel power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and will likely result in the retirement of older, marginal facilities. Due to itstheir low emission generation portfolio,portfolios, Generation and CENG will not be significantly directly affected by these regulations, representing a competitive advantage for Generation relative to electric generators that are more reliant on fossil-fuel plants. Various bills have been introduced in the U.S. House of Representatives that would prohibit or impede the U.S. EPA’s rulemaking efforts. The timing of the consideration of such legislation is unknown.
Air. Beginning with the CSAPR, the air requirements are expected to bebeing 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). TheIt is expected that the U.S. EPA has announced that it will complete a review of NAAQS in the 2011-20122012 – 2013 timeframe for particulate matter, nitrogen dioxide, sulfur dioxide and lead. This review will likely result in more stringent emissions limits on fossil-fuel fired electric generating stations. There is opposition among fossil fuel-fuel fired generation owners to the potential stringency and timing of these air regulations, and the House Commerce and Energy Committee and several of its subcommittees have held a number of hearings on these issues.
On July 7, 2011, the U.S. EPA published a final rule known as CSAPR. The CSAPR requires 2728 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. Upon preliminary review, it is expected that implementation of the 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. Several entities have challenged the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit, and requested a stay of the rule pending the Court’s consideration of the matter on the merits. Exelon believes that the CSAPR is a valid exercise of the U.S. EPA’s authority and discretion under the CAA. Exelon has received permission from the Court to intervene in support of the rule and in opposition to a stay of the rule.
On October 14, 2011 and February 7, 2012, the EPA proposed for public comment certain technical corrections to CSAPR, including correction of data errors in determining generation unit allowances and state allowance budgets. These corrections will increase the number of emission allowances available under the CSAPR. In addition, the proposal defers until 2014 penalties that will involve surrender of additional allowances should states not meet certain levels of emission reductions. This deferral is intended to increase the liquidity of allowances during the initial years of transition from CAIR to CSAPR.
Several entities challenged the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit, and requested a stay of the rule pending the Court’s consideration of the matter on the merits. Exelon received permission from the Court to intervene in support of CSAPR and in opposition to the stay. On December 30, 2011, the Court granted a stay and directed the U.S. EPA to continue the administration of CAIR in the interim. The Court ordered an expedited case management schedule that resulted in oral argument on April 13, 2012. It is unknown when the Court will issue its decision on the merits. Exelon believes that CSAPR is a valid exercise of the U.S. EPA’s authority and discretion under the Clean Air Act. Upon preliminary review, it is expected that once implemented CSAPR will modestly increase power prices over the long term, which would result in a net benefit to Generation’s and CENG’s results of operations and cash flows.
On MarchDecember 16, 2011, the U.S. EPA issuedsigned a proposedfinal rule setting national emissionto reduce emissions of toxic air pollutants from power plants and signed revisions to the new source performance standards for HAPs from coal- and oil-fired electric generating facilities (the Toxics Rule).units. The Toxics Rule would requirefinal rule, known as MATS, requires 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 expected 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 RuleMATS rule may need to upgrade existing controls or add new controls to comply. 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. Numerous entities have challenged MATS in the D.C. Circuit Court, and Exelon has petitioned the Court to intervene in support of the rule.
Exelon, along with the other co-owners of Conemaugh Generating Station are evaluatingmoving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls needed to comply withmeet the Toxics Rule. EPA’s proposed standards will require oil units to achieve highmercury removal ratesrequirements of metals.MATS by January 1, 2015. 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 ultimate natureIn addition, Generation owns three base-load, coal-fired generation units in Maryland that were acquired in the merger with Constellation – Brandon Shores, H.A. Wagner and extentC.P. Crane. However, in connection with certain of futurethe regulatory approvals required regulatory controls on HAP emissions at electric generation powerfor the merger Exelon agreed to divest these generating stations. It is anticipated that these plants will not be determined untilare well positioned to comply with CSAPR and MATS since Maryland has adopted SO2, NOx, and mercury emission limits under its Healthy Air Act and Clean Power Rule that are generally consistent with the Toxics Rule is finalized by the EPA in December 2011.requirements of CSAPR and MATS.
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. On April 13, 2012, the U.S. EPA published proposed regulations for new source performance standards (NSPS) for GHG emissions from new fossil-fueled power plants, greater than 25 MW, that would require the plants to limit CO2 emissions. Under the regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case-by-case basis.
Exelon supports comprehensive climate change legislation by the U.S Congress, including a mandatory, economy-wide cap-and-trade program for GHG emissions that balances 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,from January 2009 through January 2011, 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 provisions and remanded the rule to the EPA for further consideration and revision. 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 require closed cycle cooling (e.g., cooling towers) as the best technology available, and also provides some flexibility in the use of cost-benefit considerations and site-specific factors. The proposed rule affords the state permitting agency wide discretion to determine the best technology available, which, depending on the site characteristics, could include closed cycle cooling, advanced screen technology at the intake, or retention of the current technology. The EPA has announced that it will publish a Notice of Data Availability to obtain public comments on the national benefits of the proposed rule and alternative compliant impingement technologies.
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 retain the flexibility afforded the state permitting agencies in
applying a cost-benefitcost 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.Generation and CENG.
Waste. Under proposed U.S. EPA rules issued on June 21, 2010, coal combustion waste (CCW)residuals (CCR) would be regulated for the first time under the RCRA. The U.S. EPA is considering several options, including classification of CCWCCR either as a hazardous or non-hazardous waste.waste under RCRA. Under either option, the U.S. EPA’s intention is the ultimate elimination of surface impoundments as a waste treatment process. For 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. The Generation anticipates that the only plants in which it has an ownership interest that would be affected by the proposed rules would beare Keystone and Conemaugh.Conemaugh in Pennsylvania and Brandon Shores, H.A. Wagner, and C.P. Crane in Maryland. Keystone and Conemaugh each have on-site landfills that meet the requirements of Pennsylvania solid waste regulations for non-hazardous waste disposal. The Maryland facilities have exclusive use of a newly constructed landfill that meets the RCRA hazardous waste requirements. In connection with certain of the regulatory approvals required for the merger with Constellation, Exelon agreed to divest the Maryland generating stations and the landfill is included in the sale. As a result, Exelon does not currently expectonly the adoption of the rules as proposed tohazardous waste standards would have a significantan impact on its future capital spending requirementsExelon’s Pennsylvania facilities, and operating costs.the extent of that impact is unknown at this time. The U.S. EPA has not announced a target date for finalization of the CCWCCR rules.
See Note 1315 of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.
Regulatory and Legislative Matters
Energy Infrastructure Modernization Act (Exelon and ComEd). During the fourth quarter of 2011, EIMA was passed into law and became effective for Illinois utility companies on an opt-in basis. The legislation provides for substantial capital investment over a ten-year period to modernize Illinois’ electric utility infrastructure and for greater certainty related to the recovery of costs by a utility through a pre-established formula rate tariff. On January 6, 2012, ComEd filed its Infrastructure Investment Plan with the ICC. Under the plan, ComEd will invest approximately $2.6 billion over ten years to modernize and storm-harden its distribution system and to implement smart grid technology. These investments will be incremental to ComEd’s historical level of capital expenditures. The January 6, 2012 filing with the ICC specifically included ComEd’s $233 million investment plan for 2012. On April 23, 2012, ComEd filed its initial AMI Deployment Plan with the ICC. Implementation of the investment plan began in early 2012 while smart meter installation in homes and businesses is expected to begin later in 2012, subject to a final order from the ICC regarding ComEd’s AMI Deployment Plan, which is expected during the second quarter of 2012.
EIMA provides for a performance-based distribution formula rate tariff. On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of this initial proceeding is to establish the formula under which rates will be calculated going-forward, and the initial rate, which is expected to be lower than current rates, which will take effect within 30 days after the ICC order, which must be issued by May 31, 2012. Through an annual reconciliation process as described below, customer rates will be further adjusted effective January 2013 to provide recovery of the actual costs incurred during 2011, including recovery of and return on increases in rate base associated with capital spending under EIMA.
During the first quarter of 2012, ComEd and several intervenors filed testimony in the proceeding. The intervenors proposed various reductions to ComEd’s proposed revenues, which included changes to return on pension asset, rate base and operating expenses. On May 1, 2012, the ALJ’s issued a proposed order in ComEd’s formula rate tariff proceeding providing for a $146 million reduction in the revenue requirement being recovered in current rates, as opposed to ComEd’s final position supporting a $59 million reduction. The primary
differences between the ALJ’s proposed order and ComEd’s final position relate to different approaches to allocating certain costs and differences in timing or rate recovery mechanisms for various costs. The ALJs propose the use of average annual rate base and capital structure amounts (as opposed to year-end amounts as proposed by ComEd) and lower carrying costs on future reconciliation amounts. If approved by the ICC, the revenue requirement reduction as proposed by the ALJs would primarily delay the timing of cash flows, with a less significant impact on earnings given the annual reconciliation mechanism as described below. Use of average annual rate base and capital structure amounts (vs. year-end amounts), though, would unfavorably impact future earnings given increased regulatory lag.
ComEd is currently assessing the potential impacts of the proposed order and cannot predict the reduction in the revenue requirement the ICC may approve and which provisions of the ALJs’ proposed order will ultimately be included in the final order. As a proposed order, it has no independent legal effect as the ICC must vote on a final order which may materially vary from the findings and conclusions in the proposed order. If the ICC provides significant changes to ComEd’s filed revenue requirement request, it could have a material impact on ComEd’s future results of operations and cash flows.
As noted, EIMA provides for an annual reconciliation of the revenue requirement in effect in a given year to reflect the actual costs that the ICC determines are prudently and reasonably incurred for such year. The first year for which the reconciliation will be performed is 2011. ComEd made its initial 2011 reconciliation filing on April 30, 2012, and the rate adjustments necessary to reconcile the 2011 revenue requirement in effect to ComEd’s actual 2011 costs incurred will take effect in January 2013, after the ICC’s review. As of March 31, 2012 and December 31, 2011, ComEd recorded an estimated regulatory asset of $118 million and $84 million, respectively, which represents ComEd’s best estimate of the probable increase in distribution rates expected to be approved by the ICC to provide for recovery of prudent and reasonable costs incurred as of those dates. See Note 4 of the Combined Notes to Consolidated Financial Statements for further details related to EIMA.
Appeal of 2007 Illinois Electric Distribution Rate Case.Case (Exelon and ComEd). On September 30, 2010, the Illinois Appellate Court (Court)The ICC issued a decision in the appeals related to the ICC’san order in ComEd’s 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). ThatThe Court issued a decision ruledon September 30, 2010, ruling against ComEd on the treatment of post-test year accumulated depreciation and the recovery of system modernization costs for an AMI/Customer Applications pilot program via a rider (Rider SMP). The ICC subsequently initiated a proceeding on remand. On January 25, 2011,February 23, 2012, the ICC issued an order in the remand proceeding requiring ComEd to provide a refund of approximately $37 million to customers related to the treatment of post-test year accumulated depreciation issue. On March 26, 2012, ComEd filed a notice of appeal. ComEd has recognized for accounting purposes its best estimate of any refund obligation.
Advanced Metering Program Proceeding (Exelon and ComEd). In October 2009, the ICC approved a modified version of ComEd’s system modernization rider proposed in the 2007 Rate Case, Rider AMP (Advanced Metering Program). ComEd collected approximately $24 million under Rider AMP through December 31, 2011. Several other parties, including the Illinois Attorney General, appealed the ICC’s order on Rider AMP. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of other costs from recovery under Rider AMP to recovery through base electric distribution rates. On March 19, 2012, the Court reversed Rider AMP, concluding that the ICC’s October 2009 approval of the rider constituted single-issue ratemaking. ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court that was denied on March 30 2011. The ICC has initiated a proceeding on remand. ComEd expects that the ICC will issue a final order in earlyApril 23, 2012. ComEd filed testimony that no refunds should be required in this proceeding and in the event of any refund, the maximum refund should be $30 million. In September 2011, intervenors filed testimony that ComEd should refund approximately $37 million, including interest, to customers related to post-test year accumulated depreciation. As of September 30, 2011, ComEd has recognized for accounting purposes its best estimate ofbelieves any refund obligation subject to true-up whenassociated with Rider AMP should be prospective from no earlier than the ICC issues a final order. ComEd does not believe any of its other riders are affected by the Court’s ruling. See Note 3 of the Combined Notes to Consolidated Financial Statements for further details related to the Court’s order.
2010 Illinois Electric Distribution Rate Case. On May 24, 2011, the ICC issued an order in ComEd’s 2010 electric delivery services rate case. ComEd requested an increase in the annual 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 $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 of the order, ComEd recorded a one-time net benefit of approximately $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 nine months ended September 30, 2011. The order has been appealed to 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 Ameren 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 the 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 interveners the opportunity to review the prudence and reasonableness of costs. If the legislation were to be enacted, upon approval from ComEd’s Board of Directors, ComEd would anticipate filing annual electric distribution formula rate cases and investing an additional $2.6 billion (potentially up to $3 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.
On September 12, 2011, the Governor vetoed the bill. The legislation will now go back to the General Assembly, which may override the veto with a super-majority vote during the fourth quarter. If approved in its current form and upon approval from ComEd’s Board of Directors, ComEd expects that it would begin to achieve closer to its allowed returnCourt’s order on equity,March 19, 2012, which would have a material positivean immaterial 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.at ComEd cannot predict the eventual outcome of SB 1652 resulting from 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.
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 $316 million originally requested. The natural gas distribution rate case settlement reflects an increase of approximately $20 million in annual service revenue, which is approximately 46% of the $44 million originally requested. The approved electric and natural gas distribution rates became effective on January 1, 2011.Exelon.
See Note 3 of the Combined Notes to Consolidated Financial Statements for further details related to PECO’s rate case settlements.
Financial Reform Legislation.The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted into lawin July 2010. While the Dodd-Frank Act is focused primarily on July 21, 2010. Thisthe regulation and oversight of financial reform legislation includesinstitutions, it also provides for a provision that requires over-the-counter derivative transactions to be executed through an exchange or centrally cleared. The legislation provides an exemption from new regulatory regime for derivatives, including
mandatory clearing, exchange trading, margin requirements, for transactions that are usedand other transparency requirements. The Dodd-Frank Act, however, also preserves the ability of end users in the energy industry to hedge commercial risk like those utilized by Generation. At the same time, the legislation includes provisions under which the Commodity Futures Trading Commission (CFTC) may impose collateral requirements for transactions, including those that are used to hedge commercial risk. However, during drafting of the legislation, members of Congress issued a public letter stating that it was not their intention to impose margin and collateral requirements on counterparties that utilize transactions to hedge commercial risk. Final rules on major provisions in the legislation, including new margin requirements, will be established through rulemakings and will not take effect until 12 months after the date of enactment. On July 14, 2011,risks. In April 2012, the CFTC issued an order providing temporary reliefits rule defining swap dealers and major swap participants. Exelon is continuing to those entities engagingevaluate the rule and it is not yet known how or whether Exelon’s activity in swap transactions from certain provisions that would otherwise have appliedderivatives markets will cause all or a part of Exelon’s commercial business to be defined as of July 16, 2011 until the CFTC completes the rulemakings specified in the order. This order will expire upon the earlier of the effective date of final rules or December 31, 2011. If deemed a swap dealer Generation wouldor major swap participant. There are additional rulemakings that have not yet been issued, including the definition of swap and the capital and margin rules, which will further define the scope of the regulations and provide clarity as to the impact on us. Depending on the final rules, we could be required to execute over-the-counter derivative transactions, except those with qualifying end-users that are used to hedge commercial risk, through an exchange or central clearinghouse subject to significant new obligations.
The final regulations addressing collateral and capital requirements and exchange margin requirements; conversely,cash postings, could require us to increase collateral requirements or the amount of exchange margin cash postings in lieu of letters of credit currently issued on over-the-counter contracts. Even if deemed a qualifying end-user,the new regulations do not apply directly to us, Generation could elect not to clear such transactions. Although Exelon and Generation believe a swap dealer designation is unlikely,estimates that a substantial shift from over-the-counter sales to exchange cleared sales is estimatedmay require up to require approximately $1 billion of additional collateral.collateral postings by Generation based upon market conditions as of March 31, 2012. The level of collateral required would depend on multiple factors, including but not limited to market conditions, derivative activity levels and Generation’s credit ratings. Generation has adequate credit facilities and flexibility in its hedging program to accommodate these legislative or market changes. In addition, the final regulations may impose substantial new and ongoing compliance and infrastructure requirements on us, which may amount to several million dollars per year. Generation continues to monitor the rulemaking procedures and cannot predict the ultimate outcome that the financial reform legislation will have on its results of operations, cash flows or financial position.
New Jersey Capacity Legislation. Electric Generation Legislation and Regulations. Various states have implemented or proposed policies to subsidize generation that would artificially depress wholesale energy and capacity prices. For example, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct a 661 megawatt (MW) Combined Cycle Gas Turbine in Waldorf, Maryland, with a projected commercial operation date of June 1, 2015. The CfD provides the utilities would pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from bidding the unit into the PJM markets. The utilities are directed to meet with CPV and the MDPSC’s consultant to negotiate changes to the CfD for consideration by the MDPSC before approval. Similarly, in January 2011, New Jersey Senate Bill 2381 was enacted into law on January 28, 2011. Thispassed legislation establishedthat provides guaranteed cost recovery through a long-termCfD for the development of up to 2,000 MWs of new base load or mid-merit generation, so long as it clears in PJM’s capacity pilot program under whichmarket. Three generation developers were chosen for the New Jersey Board of Public Utilities (NJBPU) administered an RFP processCfD, which were executed by the state’s utilities under protest. Similarly, in Illinois, legislation passed 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 inSenate and clear the PJM RPM auction, likely causing them to bidcurrently being considered in the PJM RPM auctionHouse would require consumers to subsidize the development of an Integrated Gasification Combined Cycle plant by purchasing its electricity through 30 year power purchase agreements 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 prices significantly above market prices. All of these state efforts, if successful, could artificially depress wholesale capacity and/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.energy prices. Other states could seek to establish similar programs, which could substantially impair Exelon’s market driven position.position and could have a material effect on Exelon’s financial results.
Exelon has taken action against some of these anti-competitive policies through legal, legislative and regulatory challenges. Additionally, PJM’s capacity market rules include a Minimum Offer Price Rule (MOPR) that is intendedwas modified to preclude sellerscertain generators from artificially suppressing the competitive price signals for generation capacity.affecting capacity prices. See Note 34 of the Combined Notes to Consolidated Financial Statements for further details related to PJM’s MOPR.
Tax Matters
Accounting for Electric Transmission and Distribution Property Repairs. On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. For the three and nine months ended September 30, 2011, the adoption of the safe harbor resulted in a $26 million reduction to income tax expense at PECO, while Generation incurred additional income tax expense in the amount of $23 million due to a decrease in its manufacturer’s deduction. For Exelon, the adoption had a minimal effect on consolidated earnings. In addition, the adoption of the safe harbor will result in a cash tax benefit at Exelon, ComEd and PECO in the amount of approximately $300 million, $250 million and $95 million, respectively, partially offset by a cash tax detriment at Generation in the amount of $28 million. See Notes 3 and 8 of the Combined Notes to Consolidated Financial Statements for additional information on the electric transmission and distribution property repairs.
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction. 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 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 well. As a result, Exelon recorded an interest and tax benefit of $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. In addition, during the third quarter, Exelon completed additional special transfers resulting in an additional interest benefit of $3 million (after tax).
Illinois State Income Tax Legislation. 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 $11 million and $4 million of additional tax relates to Exelon Corporate and Generation, respectively, and a $10 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 and the electric transmission and distribution property repairs discussed in Note 8 of the Combined Notes to Consolidated Financial Statements.
Plant Retirements
Oyster Creek. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019, in view of the costs that might have been associated with the installation of closed-cycle cooling had operations continued to the end of its current NRC license in 2029. During the first quarter of 2011, Generation made employee retention payments of approximately $14 million that are expected to increase operating expenses by approximately $3 million (pre-tax) in each of the years 2011 through 2015.
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 will 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 will retire on May 31, 2012. 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.
Critical Accounting Policies and Estimates
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 the Exelon’s, 2010 Annual Report on Generation’s, ComEd’s and PECO’s combined 2011 Form 10-K and Constellation’s and BGE’s combined 2011
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 September 30, 2011, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2010.
Net Income (Loss) on Common Stock by Registrant
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable Variance | |||||||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2012(a) | 2011 | |||||||||||||||||||||||||||||||
Exelon | $ | 200 | $ | 668 | $ | (468 | ) | |||||||||||||||||||||||||||||
Generation | $ | 386 | $ | 605 | $ | (219 | ) | $ | 1,325 | $ | 1,548 | $ | (223 | ) | 168 | 495 | (327 | ) | ||||||||||||||||||
ComEd | 112 | 121 | (9 | ) | 295 | 246 | 49 | 87 | 69 | 18 | ||||||||||||||||||||||||||
PECO | 105 | 127 | (22 | ) | 314 | 303 | 11 | 96 | 125 | (29 | ) | |||||||||||||||||||||||||
Other(a) | (2 | ) | (8 | ) | 6 | (45 | ) | (58 | ) | 13 | ||||||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||||||
Exelon | $ | 601 | $ | 845 | $ | (244 | ) | $ | 1,889 | $ | 2,039 | $ | (150 | ) | ||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||||||
BGE | (33 | ) | 78 | (111 | ) |
(a) |
|
Results of Operations — Generation
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2012 | 2011 | |||||||||||||||||||||||||||||||
Operating revenues | $ | 2,862 | $ | 2,655 | $ | 207 | $ | 8,147 | $ | 7,428 | $ | 719 | $ | 2,739 | $ | 2,643 | $ | 96 | ||||||||||||||||||
Purchased power and fuel expense | 1,112 | 945 | (167 | ) | 3,023 | 2,442 | (581 | ) | ||||||||||||||||||||||||||||
Purchased power and fuel | 1,044 | 883 | (161 | ) | ||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Revenue net of purchased power and fuel expense(a) | 1,750 | 1,710 | 40 | 5,124 | 4,986 | 138 | ||||||||||||||||||||||||||||||
Other operating expenses | ||||||||||||||||||||||||||||||||||||
Revenue net of purchased power and fuel (a) | 1,695 | 1,760 | (65 | ) | ||||||||||||||||||||||||||||||||
Operating other expenses | ||||||||||||||||||||||||||||||||||||
Operating and maintenance | 790 | 649 | (141 | ) | 2,306 | 2,081 | (225 | ) | 1,175 | 754 | (421 | ) | ||||||||||||||||||||||||
Depreciation and amortization | 139 | 121 | (18 | ) | 416 | 344 | (72 | ) | 153 | 139 | (14 | ) | ||||||||||||||||||||||||
Taxes other than income | 67 | 57 | (10 | ) | 199 | 175 | (24 | ) | 73 | 66 | (7 | ) | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Total other operating expenses | 996 | 827 | (169 | ) | 2,921 | 2,600 | (321 | ) | 1,401 | 959 | (442 | ) | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Equity in loss of unconsolidated affiliates | (22 | ) | — | (22 | ) | |||||||||||||||||||||||||||||||
Operating income | 754 | 883 | (129 | ) | 2,203 | 2,386 | (183 | ) | 272 | 801 | (529 | ) | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Other income and deductions | ||||||||||||||||||||||||||||||||||||
Interest expense | (37 | ) | (37 | ) | — | (128 | ) | (109 | ) | (19 | ) | (54 | ) | (45 | ) | (9 | ) | |||||||||||||||||||
Other, net | (164 | ) | 192 | (356 | ) | (12 | ) | 138 | (150 | ) | 178 | 75 | 103 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Total other income and deductions | (201 | ) | 155 | (356 | ) | (140 | ) | 29 | (169 | ) | 124 | 30 | 94 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Income before income taxes | 553 | 1,038 | (485 | ) | 2,063 | 2,415 | (352 | ) | 396 | 831 | (435 | ) | ||||||||||||||||||||||||
Income taxes | 167 | 433 | 266 | 738 | 867 | 129 | 230 | 336 | 106 | |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Net income | $ | 386 | $ | 605 | $ | (219 | ) | $ | 1,325 | $ | 1,548 | $ | (223 | ) | 166 | 495 | (329 | ) | ||||||||||||||||||
Net loss attributable to noncontrolling interests | (2 | ) | — | 2 | ||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Net income on common stock | $ | 168 | $ | 495 | $ | (327 | ) | |||||||||||||||||||||||||||||
|
|
|
(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 September 30, 2011 Compared to Three Months Ended September 30, 2010. Generation’s net income for the three months ended March 31, 2012 decreased compared to the same period in 20102011 primarily due to unfavorable NDT fund performance in 2011, mark-to-market losses on economic hedging activities, unfavorable capacity pricing, higher nuclear fuel costs and higher operating and maintenance expense. Higherexpense, partially offset by favorable NDT fund performance. The increase in operating and
maintenance expense includeswas largely due to costs associated with a settlement with the impact ofFERC in March 2012, an increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion, certain acquisitiontransaction costs and increased planned nuclear refueling outageemployee-related costs associated with the higher number of refueling outage days in 2011. These unfavorable impacts were partially offset by higher revenues resulting from the expirationmerger and costs incurred as part of the PECO PPA on December 31, 2010 and favorable portfolio and market conditions inMaryland order approving the South and West region.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. Generation’s net income decreased compared to the same period in 2010 primarily due to mark-to-market losses on economic hedging activities, unfavorable NDT fund performance in 2011, higher nuclear fuel costs and higher operating and maintenance expenses. Higher depreciation and operating and maintenance expense includes the impact of an increase Generation’s decommissioning obligation for spent nuclear fuel at Zion, certain acquisition costs and increased planned nuclear refueling outage costs associated with the higher number of refueling outage days in 2011. These unfavorable impacts were partially offset by higher revenues due to the expiration of the PECO PPA on December 31, 2010 and favorable portfolio and market conditions in the South and West region.merger transaction.
Revenue Net of Purchased Power and Fuel Expense
Generation has threeThe foundation of Generation’s six reportable segments is based on the Mid-Atlantic, Midwest,geographic location of its assets, and South and West regions representingis largely representative of the different geographical areas in whichfootprints of an Independent System Operator (ISO) / Regional Transmission Operator (RTO) and/or North American Electric Reliability Corporation (NERC) region. Descriptions of each of Generation’s power marketing activitiessix reportable segments are conducted. Mid-Atlantic includes Generation’s operations primarily in Pennsylvania, New Jersey and Maryland; Midwest includes the operations in Illinois, Indiana, Michigan and Minnesota; and the South and West includes operations primarily in Texas, Georgia, Oklahoma, Kansas, Missouri, Idaho and Oregon.as follows:
• | Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina. |
• | Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the entire United States footprint of MISO, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky. |
• | New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. |
• | New York represents operations within New York ISO, which covers the state of New York in its entirety. |
• | ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas. |
• | Other Regions not considered individually significant: |
• | South represents operations in the Florida Reliability Coordinating Council (FRCC) and the remaining portions of the SERC Reliability Corporation (SERC) not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the Southwest Power Pool (SPP), covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas. |
• | West represents operations in the Western Electric Coordinating Council (WECC), which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota. |
• | Canada represents operations across the entire country of Canada and includes the Alberta Electric Systems Operator (AESO), Ontario Independent Electricity System Operator (OIESO) and the Canadian portion of MISO. |
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, PECO and PECO.BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for internally generated energy and fuel costs associated with tolling agreements. Generation’s other business activities, including retail and wholesale gas, natural gas exploration and production activities, proprietary trading, energy efficiency and demand response, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, are not allocated to regions. Further, Generation’s compensation under the reliability-must-run rate schedule, results of operations from the clean-coal assets held for sale; Brandon Shores, Wagner, and C.P. Crane, and other miscellaneous revenues, mark-to-market impact of economic hedging activities, and mark-to-market activitiesamortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger are also not allocated to a region.
For the three and nine months ended September 30,March 31, 2012 and 2011, and 2010, Generation’s revenue net of purchased power and fuel expense by region were as follows:
Three Months Ended September 30, | Variance | % Change | ||||||||||||||
2011 | 2010 | |||||||||||||||
Mid-Atlantic(a)(b) | $ | 836 | $ | 564 | $ | 272 | 48.2 | % | ||||||||
Midwest(b) | 853 | 1,044 | (191 | ) | (18.3 | %) | ||||||||||
South and West | 98 | (11 | ) | 109 | 990.9 | % | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total electric revenue net of purchased power and fuel expense | $ | 1,787 | $ | 1,597 | $ | 190 | 11.9 | % | ||||||||
Trading portfolio | 2 | — | 2 | n.m. | ||||||||||||
Mark-to-market gains (losses) | (91 | ) | 163 | (254 | ) | n.m. | ||||||||||
Other(c)(d) | 52 | (50 | ) | 102 | n.m. | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total revenue net of purchased power and fuel expense | $ | 1,750 | $ | 1,710 | $ | 40 | 2.3 | % | ||||||||
|
|
|
|
|
|
|
|
Mid-Atlantic(a)(b) Midwest(b) South and West Total electric revenue net of purchased power and fuel expense Trading portfolio Mark-to-market gains (losses) Other(c)(d) Total revenue net of purchased power and fuel expense Mid-Atlantic (b) Midwest (c) New England New York ERCOT Other Regions (d) Total electric revenue net of purchased power and fuel Proprietary Trading Mark-to-market gains (losses) Other (e) Total revenue net of purchased power and fuel Nine Months Ended
September 30, Variance % Change 2011 2010 $ 2,573 $ 1,760 $ 813 46.2 % 2,704 3,054 (350 ) (11.5 %) 84 (102 ) 186 182.4 % $ 5,361 $ 4,712 $ 649 13.8 % 24 25 (1 ) (4.0 %) (363 ) 273 (636 ) n.m. 102 (24 ) 126 n.m. $ 5,124 $ 4,986 $ 138 2.8 % Three Months Ended
March 31, 2012 (a) 2011 Variance % Change $ 770 $ 914 $ (144 ) (15.8 )% 817 965 (148 ) (15.3 )% 39 2 37 n.m. 8 — 8 n.m. 34 4 30 n.m. 14 (8 ) 22 n.m. 1,682 1,877 (195 ) (10.4 )% (4 ) 5 (9 ) n.m. 60 (146 ) 206 (141.1 )% (43 ) 24 (67 ) n.m. $ 1,695 $ 1,760 $ (65 ) (3.7 )%
(a) |
|
(b) | Results of transactions with PECO and |
(c) |
|
(d) | Other Regions includes South, West and Canada, which are not considered individually significant. |
(e) | Other represents activities not allocated to a region and includes retail and wholesale gas, upstream natural gas, demand response, energy efficiency, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems. In |
Generation’s supply sources by region are summarized below:
Three Months Ended September 30, | Variance | % Change | ||||||||||||||
Supply source (GWh) | 2011 | 2010 | ||||||||||||||
Nuclear generation(a) | ||||||||||||||||
Mid-Atlantic | 12,158 | 12,076 | 82 | 0.7 | % | |||||||||||
Midwest | 23,887 | 23,675 | 212 | 0.9 | % | |||||||||||
Fossil and renewable generation | ||||||||||||||||
Mid-Atlantic(a)(b) | 1,724 | 2,582 | (858 | ) | (33.2 | %) | ||||||||||
Midwest(c) | 88 | 16 | 72 | n.m. | ||||||||||||
South and West(c) | 1,463 | 691 | 772 | 111.7 | % | |||||||||||
Purchased power(d) | ||||||||||||||||
Mid-Atlantic | 702 | 599 | 103 | 17.2 | % | |||||||||||
Midwest | 1,756 | 1,774 | (18 | ) | (1.0 | %) | ||||||||||
South and West | 3,815 | 4,084 | (269 | ) | (6.6 | %) | ||||||||||
Total supply by region | ||||||||||||||||
Mid-Atlantic | 14,584 | 15,257 | (673 | ) | (4.4 | %) | ||||||||||
Midwest | 25,731 | 25,465 | 266 | 1.0 | % | |||||||||||
South and West | 5,278 | 4,775 | 503 | 10.5 | % | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total supply | 45,593 | 45,497 | 96 | 0.2 | % | |||||||||||
|
|
|
|
|
|
|
|
Supply source (GWh) Nuclear generation(a) Mid-Atlantic Midwest Fossil and renewable generation Mid-Atlantic(a)(b) Midwest(c) South and West(c) Purchased power(d) Mid-Atlantic Midwest South and West Total supply by region Mid-Atlantic Midwest South and West Total supply Supply source in GWh Nuclear generation (b) Mid-Atlantic Midwest Total Nuclear Generation Fossil and Renewables (b) Mid-Atlantic (b)(d) Midwest New England New York ERCOT (e) Other Regions (f) Total Fossil and Renewables Purchased power Mid-Atlantic (c ) Midwest New England New York (c) ERCOT (e) Other Regions (f) Total Purchased Power Total supply/sales by region (g) Mid-Atlantic (h) Midwest (i) New England New York ERCOT Other Regions (f) Total supply/sales by region Nine Months Ended
September 30, Variance % Change 2011 2010 35,700 35,544 156 0.4 % 68,704 69,352 (648 ) (0.9 %) 5,943 7,321 (1,378 ) (18.8 %) 408 23 385 n.m. 2,610 1,120 1,490 133.0 % 2,159 1,476 683 46.3 % 4,827 5,256 (429 ) (8.2 %) 8,408 9,480 (1,072 ) (11.3 %) 43,802 44,341 (539 ) (1.2 %) 73,939 74,631 (692 ) (0.9 %) 11,018 10,600 418 3.9 % 128,759 129,572 (813 ) (0.6 %) Three Months Ended
March 31, 2012 (a) 2011 Variance % Change 12,064 12,370 (306 ) (2.5 )% 23,198 22,822 376 1.6 % 35,262 35,192 70 0.2 % 1,791 2,162 (371 ) (17.2 )% 272 157 115 73.2 % 889 4 885 n.m. — — — 0 % 840 151 689 n.m. 819 358 461 128.8 % 4,611 2,832 1,779 62.8 % 2,577 750 1,827 n.m. 2,552 1,412 1,140 80.7 % 1,100 — 1,100 n.m. 935 — 935 n.m. 2,832 1,625 1,207 74.3 % 1,769 556 1,213 n.m. 11,765 4,343 7,422 170.9 % 16,432 15,282 1,150 7.5 % 26,022 24,391 1,631 6.7 % 1,989 4 1,985 n.m. 935 — 935 n.m. 3,672 1,776 1,896 106.8 % 2,588 914 1,674 n.m. 51,638 42,367 9,271 21.9 %
(a) | Includes |
(b) | Includes |
(c) |
|
(d) |
|
(e) | Generation from Wolf Hollow is included in purchased power for the period ending March 31, 2011 and included within Fossil and Renewables for the period ending March 31, 2012, due to the acquisition of Wolf Hollow in August, 2011. |
(f) | Other Regions includes South, West and Canada, which are not considered individually significant. |
(g) | Excludes physical proprietary trading volumes of 1,888 GWh and |
Generation’s sales are summarized below:
Three Months Ended September 30, | Variance | % Change | ||||||||||||||
Sales (GWh)(a) | 2011 | 2010 | ||||||||||||||
PECO(c) | — | 11,976 | (11,976 | ) | (100.0 | %) | ||||||||||
Market and retail(d) | 45,593 | 33,521 | 12,072 | 36.0 | % | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total electric sales | 45,593 | 45,497 | 96 | 0.2 | % | |||||||||||
|
|
|
|
|
|
|
|
Nine Months Ended September 30, | Variance | % Change | ||||||||||||||
Sales (GWh)(a) | 2011 | 2010 | ||||||||||||||
ComEd(b) | — | 5,323 | (5,323 | ) | (100.0 | %) | ||||||||||
PECO(c) | — | 32,247 | (32,247 | ) | (100.0 | %) | ||||||||||
Market and retail(d) | 128,759 | 92,002 | 36,757 | 40.0 | % | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total electric sales | 128,759 | 129,572 | (813 | ) | (0.6 | %) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
Includes |
(i) | Includes sales to ComEd under the RFP of 2,210 GWh and 1,251 GWh for the three months ended March 31, 2012 and 2011, respectively. |
The following table presents electric revenue net of purchased power and fuel expense per MWh of electricity sold during the three and nine months ended September 30, 2011March 31, 2012 as compared to the same periods in 2010.three months ended March 31, 2011.
Three Months Ended September 30, | % Change | |||||||||||
$/MWh | 2011 | 2010 | ||||||||||
Mid-Atlantic(a)(b) | $ | 57.32 | $ | 36.97 | 55.0 | % | ||||||
Midwest(a)(c) | $ | 33.15 | $ | 41.00 | (19.1 | %) | ||||||
South and West | $ | 18.57 | $ | (2.30 | ) | 907.4 | % | |||||
Electric revenue net of purchased power and fuel expense per MWh(d) | $ | 39.19 | $ | 35.11 | 11.6 | % |
Nine Months Ended September 30, | % Change | |||||||||||
$/MWh | 2011 | 2010 | ||||||||||
Mid-Atlantic(a)(b) | $ | 58.74 | $ | 39.69 | 48.0 | % | ||||||
Midwest(a)(c) | $ | 36.57 | $ | 40.92 | (10.6 | %) | ||||||
South and West | $ | 7.62 | $ | (9.62 | ) | 179.2 | % | |||||
Electric revenue net of purchased power and fuel expense per MWh(d) | $ | 41.64 | $ | 36.37 | 14.5 | % |
Three Months Ended March 31, | ||||||||||||
$/MWh (a) | 2012 (a) | 2011 | % Change | |||||||||
Mid-Atlantic(b) | $ | 46.86 | $ | 59.92 | (21.8 | )% | ||||||
Midwest (c) | 31.40 | 39.60 | (20.7 | )% | ||||||||
New England | 19.61 | n.m. | n.m. | |||||||||
New York | 8.56 | n.m. | n.m. | |||||||||
ERCOT | 9.26 | 2.54 | n.m. | |||||||||
Other Regions (d) | 5.41 | (8.81 | ) | n.m. | ||||||||
Electric revenue net of purchased power and fuel expense per MWh (e)(f) | 32.57 | 44.30 | (26.5 | )% |
(a) |
|
(b) | Includes sales to PECO of |
(c) | Includes sales to ComEd of |
(d) | Other Regions includes South, West and Canada, which are not considered individually significant. |
(e) | Revenue net of purchased power and fuel expense per MWh represents the average margin per MWh of electricity sold during the three |
(f) | Excludes retail gas activity, proprietary trading portfolio activity, compensation under the reliability-must-run rate schedule and |
Mid-AtlanticMid-Atlantic.
Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010. The increase$144 million decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic of $272 million was primarily due to increased realized margins on the volumes previously sold under Generation’s PPA with PECO, which expired on December 31, 2010, partially offset by increased nuclear fuel costs.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. The increase in revenue net of purchased power and fuel expense in the Mid-Atlantic of $813 million was primarily due to increased realized margins on the volumes previously sold under Generation’s PPA with PECO, which expired on December 31, 2010, partially offset by increased nuclear fuel costs.
Midwest
Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010. The decrease in revenue net of purchased power and fuel expense in the Midwest of $191 million was primarily due to lower capacity revenues, lower realized power prices and increased nuclear fuel costs, partially offset by increased revenues due to the acquisition of Exelon Wind in December 2010.costs.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. Midwest.The $148 million decrease in revenue net of purchased power and fuel expense in the Midwest of $350 million was primarily due to decreasedlower capacity revenues, lower realized margins in 2011 for the volumes previously sold under the 2006 ComEd auction contracts, higher congestion costspower prices and increased nuclear fuelfuels costs. These decreases were partially offset by increased capacity revenues,decreased congestion costs and favorable settlements underon the ComEd swap and the additional revenue from the acquisition of Exelon Wind in December 2010.swap.
South and West
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 September 30, 2011 Compared to Three Months Ended September 30, 2010New England.. The $37 million increase in revenue net of purchased power and fuel expense in the South and West of $109 millionNew England was primarily due to favorable pricing as a result of extreme weatherthe Constellation merger. Prior to the merger, New England was not a significant contributor to revenue net of purchased power and favorable market conditions in August 2011 and the additional revenue from the acquisition of Exelon Wind in December 2010.fuel expense at Generation.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010New York.. The $8 million increase in revenue net of purchased power and fuel expense in New York was as a result of the SouthConstellation merger. Prior to the merger, New York was not a significant contributor to revenue net of purchased power and Westfuel expense at Generation.
ERCOT. The $30 million increase in revenue net of $186 millionpurchased power and fuel expense in ERCOT was primarily driven byas a result of the performanceConstellation merger. The legacy Generation ERCOT portfolio was relatively flat period over period.
Other Regions. The $22 million increase in revenue net of our generating units during extreme weather events that occurredpurchased power and fuel expense in TexasOther Regions was primarily as a result of the Constellation merger. Additionally, increased production at legacy Generation wind facilities resulted in February and August 2011, in addition to the impact of additional revenue from the acquisition of Exelon Wind in December 2010 and higher realized margins due to favorable market conditions.increased revenues.
Mark-to-marketMark-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 September 30, 2011 Compared to Three Months Ended September 30, 2010. Mark-to-market lossesgains on powereconomic hedging activities were $71$60 million for the three months ended September 30, 2011, including the impact of the changes in ineffectiveness,March 31, 2012 compared to gainslosses of $107$146 million for the three months ended September 30, 2010. Mark-to-market losses on fuel hedging activities were $20 million for the three months ended September 30, 2011 compared to gains of $56 million for the three months ended September 30, 2010. In general, the mark-to-market losses incurred in 2011 represent the realization of in-the-money hedge transactions during the period.March 31, 2011. See Notes 56 and 67 of the Combined Notes to the Consolidated Financial Statements for information on losses associated with mark-to-market derivatives.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. Mark-to-market losses on power hedging activities were $260 million for the nine months ended September 30, 2011, including the impact of the changes in ineffectiveness, compared to gains of $142 million for the nine months ended September 30, 2010. Mark-to-market losses on fuel hedging activities were $103 million for the nine months ended September 30, 2011 compared to gains of $131 million for the nine months ended September 30, 2010. In general, the mark-to-market losses incurred in 2011 represent the realization of in-the-money hedge transactions during the period. See Notes 5 and 6 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
OtherOther.
Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010. The increase$67 million decrease in other revenue net of purchased power and fuel expense iswas primarily due to the impactsamortization of the impairment charge of certain emission allowances recognized in September 2010, additional other wholesale fuel sales in 2011, as well asacquired energy contracts recorded at fair value at the merger date. This decrease was partially offset by compensation under the reliability-must-run rate schedule, further described in Note 11results from retail gas, energy efficiency, energy management and demand response, upstream natural gas and the design and construction of the Combined Notes to the Consolidated Financial Statements.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. The increase inrenewable energy facilities. In addition, other revenue net of purchased power and fuel expense is primarily due toincludes the impactsresults of Brandon Shores, H.A. Wagner and C.P. Crane, the generating facilities planned for divestiture as a result of the impairment charge of certain emission allowances recognized in September 2010, as well as the compensation under the reliability-must-run rate schedule further described inExelon and Constellation merger. See Note 113 of the Combined Notes to the Consolidated Financial Statements.Statements for information regarding contract intangibles and assets planned for divestiture as a result of the Constellation Merger.
Nuclear Fleet Capacity Factor and Production CostsCosts.
The following table presents nuclear fleet operating data for the three and nine months ended September 30, 2011March 31, 2012 as compared to the same periods in September 30, 2010,2011, for the Generation-operatedExelon-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 September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2012 | 2011 | |||||||||||||||||||
Nuclear fleet capacity factor(a) | 95.8 | % | 95.4 | % | 93.4 | % | 94.2 | % | 93.6 | % | 94.8 | % | ||||||||||||
Nuclear fleet production cost per MWh(a) | $ | 17.35 | $ | 15.61 | $ | 18.47 | $ | 17.00 | $ | 20.06 | $ | 18.73 |
(a) | Excludes Salem, which is operated by PSEG Nuclear, |
Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010. The change in the nuclear fleet capacity factor was not materialdecreased primarily because thedue to an increase in refueling outage days excluding Salem outages, during the three months ended September 30, 2011March 31, 2012 compared to the same period in 2010 was completely offset by the decrease in non-refueling outage days during comparable periods.2011. For the three months ended September 30,March 31, 2012 and 2011, and 2010, refueling outage days totaled 3367 and 19,44, respectively. The increase in refueling outage days was primarily due to one additional refueling outagethe timing in which the outages were performed in 20112012 compared to 2010. For the three months ended September 30, 2011 and 2010, non-refueling outage days totaled 3 and 19, respectively. Higher2011. An increase in nuclear fuel costs and higher plant operating and maintenance expensecosts resulted in a higher production cost per MWh for the three months ended September 30, 2011March 31, 2012 as compared to the same period in 2010.2011.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. The nuclear fleet capacity factor decreased primarily due to more refueling outage days, excluding Salem outages, during the nine months ended September 30, 2011 compared to the same period in 2010 . For the nine months ended September 30, 2011 and 2010, refueling outage days totaled 180 and 164, respectively. Higher nuclear fuel costs, higher plant operating and maintenance expense and a lower number of net MWhs generated resulted in higher production cost per MWh for the nine months ended September 30, 2011 as compared to the same period in 2010.
Operating and Maintenance Expense
The changeschange in operating and maintenance expense for the three and nine months ended September 30, 2011March 31, 2012 compared to the same periodsperiod in 2010,2011, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Labor, other benefits, contracting and materials | $ | 31 | $ | 81 | ||||
Nuclear refueling outage costs, including the co-owned Salem plant(a) | 25 | 35 | ||||||
Exelon Wind(b) | 10 | 31 | ||||||
Asset retirement obligation increase(c) | 28 | 28 | ||||||
Acquisition costs(d) | 15 | 16 | ||||||
Other(e) | 32 | 34 | ||||||
|
|
|
| |||||
Increase in operating and maintenance expense | $ | 141 | $ | 225 | ||||
|
|
|
|
FERC settlement(a) Constellation merger and integration costs Labor, other benefits, contracting and materials Maryland commitments(b) Corporate allocations(c) Pension and non-pension postretirement benefits expense Nuclear refueling outage costs, including the co-owned Salem plant(d) Plant divestitures Other Increase in operating and maintenance expense Increase
(Decrease) $ 195 73 52 35 23 15 14 6 8 $ 421
(a) | Reflects costs incurred as part of a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions. |
(b) | Reflects costs incurred as part of the Maryland order approving the merger transaction. |
(c) | Reflects the impact of an increased share of corporate allocated costs due to the merger. |
(d) | Reflects the impact of increased planned refueling |
|
|
|
|
Depreciation and Amortization
The increase in depreciation and amortization expense for the three and nine months ended September 30, 2011 asMarch 31, 2012 compared to the three and nine months ended September 30, 2010same period in 2011 was primarily due to higher plant balances due to capital additions, upgrades to existing facilities andresulting from the acquisitionaddition of Exelon Wind.Constellation’s plant balances. The increase in depreciation and amortization expense was also due to the change in the estimated useful life associated with the early retirement of Oyster Creek announced in December 2010. The change in estimated useful life is further described in Note 13 of the Combined Notescapital additions and upgrades to Consolidated Financial Statements.legacy facilities.
Taxes Other Than Income
The increase in taxes other than income for the three and nine months ended September 30, 2011 asMarch 31, 2012 compared to the three and nine months ended September 30, 2010same period in 2011 was primarily due to increased gross receipt taxes related to retail sales in the Mid-Atlantic region.NewEnergy sales. These gross receipt taxes are recovered in revenue, and as a result, have no net impact to Generation’s results of operations.comprehensive income.
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates was $22 million for the three months ended March 31, 2012 due to the addition of Generation’s ownership interest in CENG in connection with the merger. CENG recorded a loss primarily due to planned nuclear refueling outage days from March 12, 2012 through March 31, 2012.
Interest Expense
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. The increase in interest expense for the ninethree months ended September 30, 2011 asMarch 31, 2012 compared to the nine months ended September 30, 2010same period in 2011 was primarily due to an increase inthe long-term debt outstanding as a result of issuancesassumed in connection with the third quarter of 2010.merger.
Other, Net
Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010. The decrease in other,Other, net primarily reflects the change in the net unrealized gains (losses)gain/loss position for the three months ended March 31, 2012 compared to the same period in 2011 related to the NDT funds of theits Non-Regulatory Agreement Units as
described in the table below. Other, net also reflects a $36 million bargain purchase gain associated with the August 2011 acquisition of Wolf Hollow.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. The decrease in 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 the table below. The decrease in other, net is partially offset by the impact of a $32 million one-time interest income from the NDT fund special transfer tax deduction recognized in the second quarter of 2011 and a $36 million bargain purchase gain associated with the August 2011 acquisition of Wolf Hollow. Other, net also reflects $25$64 million of expenseincome in 20112012 compared to $48$27 million of expenseincome in 20102011 related to the contractual elimination of income tax expenseexpenses in 2012 and 2011, respectively, associated with the NDT funds of the Regulatory Agreement Units.
The following table provides unrealized and realized gains and losses on the NDT funds of the Non-Regulatory Agreement Units recognized in other,Other, net for the three and nine months ended September 30, 2011March 31, 2012 and 2010:2011:
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2012 | 2011 | |||||||||||||||||||
Net unrealized gains (losses) on decommissioning trust funds | $ | (141 | ) | $ | 107 | $ | (88 | ) | $ | 48 | ||||||||||||||
Net unrealized gains on decommissioning trust funds | $ | 65 | $ | 43 | ||||||||||||||||||||
Net realized gains (losses) on sale of decommissioning trust funds | $ | (1 | ) | $ | 1 | $ | (3 | ) | $ | 1 | 37 | (2 | ) |
Effective Income Tax Rate
Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010. The effective income tax rate was 30.2%58.1% for the three months ended September 30, 2011March 31, 2012 compared to 41.7%40.4% for the same period during 2010. The decrease in the effective income tax rate was primarily due to unrealized losses on the qualified decommissioning trust funds in 2011, compared to the unrealized gains in 2010. The effective income tax rate also decreased as the result of benefits associated with production tax credits at Exelon Wind. The decrease was partially offset by the impact of a reduction in Generation’s manufacturing deduction benefits given reduced taxable income as a result of electing the safe harbor method of tax accounting for electric transmission and distribution property at ComEd and PECO for the 2011 and 2010 tax years.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. The effective income tax rate was 35.8% for the nine months ended September 30, 2011 compared to 35.9% for the same period during 2010.
2011. See Note 89 — of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.
Results of Operations — ComEd
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | |||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||
Operating revenues | $ | 1,784 | $ | 1,918 | $ | (134 | ) | $ | 4,694 | $ | 4,832 | $ | (138 | ) | ||||||||||
Purchased power expense | 932 | 1,112 | 180 | 2,436 | 2,636 | 200 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Revenue net of purchased power expense(a) | 852 | 806 | 46 | 2,258 | 2,196 | 62 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Other operating expenses | ||||||||||||||||||||||||
Operating and maintenance | 353 | 298 | (55 | ) | 846 | 733 | (113 | ) | ||||||||||||||||
Operating and maintenance for regulatory required programs | 43 | 22 | (21 | ) | 84 | 62 | (22 | ) | ||||||||||||||||
Depreciation and amortization | 135 | 126 | (9 | ) | 405 | 386 | (19 | ) | ||||||||||||||||
Taxes other than income | 78 | 81 | 3 | 226 | 188 | (38 | ) | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total other operating expenses | 609 | 527 | (82 | ) | 1,561 | 1,369 | (192 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Operating income | 243 | 279 | (36 | ) | 697 | 827 | (130 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Other income and deductions | ||||||||||||||||||||||||
Interest expense, net | (86 | ) | (82 | ) | (4 | ) | (257 | ) | (300 | ) | 43 | |||||||||||||
Other, net | 16 | 3 | 13 | 24 | 14 | 10 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total other income and deductions | (70 | ) | (79 | ) | 9 | (233 | ) | (286 | ) | 53 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Income before income taxes | 173 | 200 | (27 | ) | 464 | 541 | (77 | ) | ||||||||||||||||
Income taxes | 61 | 79 | 18 | 169 | 295 | 126 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Net income | $ | 112 | $ | 121 | $ | (9 | ) | $ | 295 | $ | 246 | $ | 49 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||
2012 | 2011 | |||||||||||
Operating revenues | $ | 1,388 | $ | 1,466 | $ | (78 | ) | |||||
Purchased power expense | 620 | 789 | 169 | |||||||||
|
|
|
|
|
| |||||||
Revenue net of purchased power expense(a) | 768 | 677 | 91 | |||||||||
|
|
|
|
|
| |||||||
Other operating expenses | ||||||||||||
Operating and maintenance | 318 | 266 | (52 | ) | ||||||||
Depreciation and amortization | 149 | 134 | (15 | ) | ||||||||
Taxes other than income | 75 | 77 | 2 | |||||||||
|
|
|
|
|
| |||||||
Total other operating expenses | 542 | 477 | (65 | ) | ||||||||
|
|
|
|
|
| |||||||
Operating income | 226 | 200 | 26 | |||||||||
|
|
|
|
|
| |||||||
Other income and deductions | ||||||||||||
Interest expense, net | (82 | ) | (85 | ) | 3 | |||||||
Other, net | 4 | 4 | — | |||||||||
|
|
|
|
|
| |||||||
Total other income and deductions | (78 | ) | (81 | ) | 3 | |||||||
|
|
|
|
|
| |||||||
Income before income taxes | 148 | 119 | 29 | |||||||||
Income taxes | 61 | 50 | (11 | ) | ||||||||
|
|
|
|
|
| |||||||
Net income | $ | 87 | $ | 69 | $ | 18 | ||||||
|
|
|
|
|
|
(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 incomeIncome
Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010. The increase in ComEd’s net income for the three months ended September 30, 2011 was lower thanMarch 31, 2012 compared to the same period in 2010 primarily due to higher operating and maintenance expense resulting from several significant 2011 storms in ComEd’s service territory. The decrease to net income was partially offset by higher electric distribution rates, effective June 1, 2011, pursuant to the ICC order in ComEd’s 2010 rate case.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. ComEd’s net income for the nine months ended September 30, 2011 was higher than the same period in 2010 primarily due to higher electric distribution rates, effective June 1, 2011, and one-time net benefits recognized in May 2011,increased revenues resulting from the reconciliation of ComEd’s distribution revenue requirement pursuant to the ICC orderEIMA. The increase in ComEd’s 2010 rate case. In addition, net income was higher due to the remeasurement of uncertain income tax positions in 2010 related to the 1999 sale of ComEd’s fossil generating assets. The remeasurement resulted in increased interest expense and income tax expense recorded in the second quarter of 2010. These increases to net income were partially offset by unfavorable weather conditions, higher operating and maintenance expense
resulting from several significant 2011 storms in ComEd’s service territory, by the benefit recorded in 2010 resulting from the ICC’s approval of ComEd’s uncollectible accounts expense rider mechanism, and the accrual of estimated future Illinois utility distribution tax refunds for the 2008higher depreciation and 2009 tax years recorded in the second quarter of 2010.amortization expense.
Operating revenues and purchased power expenseRevenues Net of Purchased Power Expense
There are certain drivers toof 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 revenuerevenues net of purchased power expense. See Note 34 of the Combined Notes to Consolidated Financial Statements 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 customercustomer’s choice of electric generation supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation services. The number of retail customers purchasing electricity from competitive electric generation suppliers was 249,714492,079 and 61,822 at September 30,74,453 as of March 31, 2012 and 2011, and 2010, respectively, representing 7%13% and 2% of total retail customers, respectively. The significant increase in 2012 is primarily associated with the residential customer class. Retail deliveries purchased from competitive electric generation suppliers represented 53%60% and 54%53% of ComEd’s retail kWh sales for the three and nine months ended September 30,March 31, 2012 and 2011, respectively, as compared to 49% and 51% for the three and nine months ended September 30, 2010, respectively.
The changes in ComEd’s electric revenuerevenues net of purchased power expense for the three and nine months ended September 30, 2011March 31, 2012 compared to the same periodsperiod in 20102011 consisted of the following:
Three Months Ended September 30, 2011 | Nine Months Ended September 30, 2011 | |||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Pricing (2010 Rate Case) | $ | 44 | $ | 57 | $ | 33 | ||||||
Distribution formula rate reconciliation, net | 26 | |||||||||||
Revenues subject to refund, net | 23 | 3 | 24 | |||||||||
Regulatory required programs cost recovery | 21 | 22 | ||||||||||
Regulatory required programs | 16 | |||||||||||
Transmission | 4 | 9 | 9 | |||||||||
Volume — delivery | (7 | ) | (12 | ) | 1 | |||||||
Weather — delivery | (9 | ) | (10 | ) | (18 | ) | ||||||
Uncollectible accounts recovery, net | (10 | ) | (15 | ) | ||||||||
Other | (20 | ) | 8 | |||||||||
|
|
| ||||||||||
Total increase | $ | 46 | $ | 62 | $ | 91 | ||||||
|
|
|
Pricing (2010 Rate Case).
The ICC issued an order in the 2010 Rate Case approving an increase in ComEd’s annual electric distribution revenue requirement. The order became effective June 1, 2011, resulting in higher revenues for the three and nine months ended September 30, 2011March 31, 2012 compared to the same periodsperiod in 2010.2011. See Note 34 of the Combined Notes to Consolidated Financial Statements for additional information.
Distribution formula rate reconciliation, net.EIMA provides for a performance-based formula rate tariff. The legislation provides for an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. ComEd made its initial reconciliation filing on April 30, 2012 and the adjusted rates will take effect in January 2013 after ICC review. During the three months ended March 31, 2012, ComEd recorded a $45 million increase in revenues associated with the first quarter of the 2012 reconciliation and a $19 million reduction to the 2011 reconciliation. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.
Revenues subject to refund, netnet.
ComEd records revenues subject to refund based upon its best estimate of customer collections that may be required to be refunded. As a result of the September 30, 2010 Illinois Appellate Court (Court) decision in the 2007 Rate Case that ruled against ComEd on the treatment of post-test year accumulated depreciation and the
recovery of system modernization costs via Rider SMP, ComEd began recording revenue subject to refund prospectively. In addition, ComEd began recording revenue subject to refund on June 1, 2010 relating to the recovery of Cash Working Capital (CWC) through its energy procurement rider. Based onDuring the 2010 Rate Case order as well as the proceeding on remand associated with the Court order,three months ended March 31, 2012, ComEd has updated its revenuedid not record revenues subject to refund reserve. As of September 30, 2011, ComEd has recorded its best estimate ofassociated with any refund obligations. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.matters.
Regulatory required programs cost recoveryprograms.
Revenues related to regulatory required programs are the recoveries from customers offor costs forof various legislative and/or regulatory programs on a full and current basis through approved regulated rates. Programs include ComEd’s uncollectible accounts tariff, energy efficiency and demand response and purchased power administrative costs. An equal and offsetting amount has been reflected in operating and maintenance for regulatory required programsexpense during the periods presented. See Note 3 ofRefer to the Combined Notes to Financial Statementsoperating and maintenance expense discussion below for additional information.information on included programs.
TransmissionTransmission.
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 expenses and investments plus forecasted 2011 capital additions. Transmission revenues net of purchased power expense vary from year to year based upon fluctuations in the underlying costs, and investments being recovered. See Note 3recovered and other billing determinants, such as the highest daily peak load from the previous calendar year. ComEd set a record for the highest daily peak load of 23,753 MWs on July 20, 2011 which was reflected in the Combined Notes to Consolidated Financial Statements for additional information.determination of transmission revenues billed beginning January 1, 2012.
Volume — deliverydelivery.
Revenues net of purchased power expense decreasedincreased as a result of lowerhigher delivery volume, exclusive of the effects of weather, reflecting an extra day in February 2012 for leap year, partially offset by decreased average usage per residential and small commercial and industrial customer for the three and nine months ended September 30, 2011,March 31, 2012 compared to the same periodsperiod in 2010.2011.
Weather — deliverydelivery.
RevenuesThe decrease in revenues net of purchased power expense were lower infor the three and nine months ended September 30, 2011,March 31, 2012 compared to the same periodsperiod in 2010,2011 was primarily due to unfavorable weather conditions despite settingas a newresult of Illinois experiencing the warmest first quarter on record for highest daily peak load experienced to date of 23,753 MWs on July 20, 2011.in 2012. 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. The historically warm weather led to a decrease in the number of heating degree days recorded for the three months ended March 31, 2012 compared to the same period in 2011.
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 with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months.territory. The changes in heating and cooling degree days in ComEd’s service territory for the three and nine months ended September 30,March 31, 2012 compared to the same period in 2011 and 2010, consisted of the following:
% Change | 2012 | 2011 | Normal | % Change | ||||||||||||||||||||||||||||||||||||
Heating and Cooling Degree-Days | 2011 | 2010 | Normal | From 2010 | From Normal | |||||||||||||||||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
2012 | 2011 | Normal | From 2011 | From Normal | ||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 147 | 70 | 110 | 110.0 | % | 33.6 | % | (28.5 | )% | (24.7 | )% | |||||||||||||||||||||||||||||
Cooling Degree-Days | 785 | 854 | 624 | (8.1 | )% | 25.8 | % | 39 | — | — | n/a | n/a | ||||||||||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 4,302 | 3,699 | 4,084 | 16.3 | % | 5.3 | % | |||||||||||||||||||||||||||||||||
Cooling Degree-Days | 1,022 | 1,166 | 848 | (12.3 | )% | 20.5 | % |
Uncollectible accounts recovery, net
Represents recoveries under ComEd’s uncollectible accounts tariff.
Other
Other revenues, which can vary period to period, include rental revenues, revenues related to late payment charges, assistance provided to unaffiliated utilities through mutual assistance programs and recoveries of environmental remediation costs associated with MGP sites.
Operating and Maintenance Expense
Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2012 | 2011 | |||||||||||
Operating and maintenance expense — baseline | ||||||||||||
Operating and maintenance expense — regulatory required | $ | 261 | $ | 225 | $ | 36 | ||||||
programs(a) | 57 | 41 | 16 | |||||||||
|
|
|
|
|
| |||||||
Total operating and maintenance expense | 318 | 266 | 52 | |||||||||
|
|
|
|
|
|
(a) | 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 approved regulated rates. An equal and offsetting amount has been reflected in operating revenues. |
The changes in operating and maintenance expense for the three and nine months ended September 30, 2011March 31, 2012 compared to the same periodsperiod in 2010,2011, consisted of the following:
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Uncollectible accounts expense(a) | ||||||||
One-time impact of 2010 ICC order(b) | $ | — | $ | 60 | ||||
Provision | 3 | 5 | ||||||
Recovery, net(c) | (13 | ) | (20 | ) | ||||
|
|
|
| |||||
(10 | ) | 45 | ||||||
Storm-related costs(d) | 67 | 72 | ||||||
Labor, other benefits, contracting and materials | 9 | 43 | ||||||
Discrete impacts from 2010 Rate Case order(e) | — | (32 | ) | |||||
Other | (11 | ) | (15 | ) | ||||
|
|
|
| |||||
Increase in operating and maintenance expense | $ | 55 | $ | 113 | ||||
|
|
|
|
Increase (Decrease) | ||||
Baseline | ||||
Labor, other benefits, contracting and materials(a) | $ | 28 | ||
Pension and non-pension postretirement benefits expense | 8 | |||
Other | — | |||
|
| |||
36 | ||||
Regulatory required programs | ||||
Energy efficiency and demand response programs | 17 | |||
Uncollectible accounts expense — provision | 4 | |||
Uncollectible accounts expense — recovery, net(b) | (5 | ) | ||
Purchased power administrative costs | — | |||
|
| |||
16 | ||||
|
| |||
Increase in operating and maintenance expense | $ | 52 | ||
|
|
(a) | The increase includes contracting costs resulting from new projects associated with EIMA. See Note 4 of the Combined Notes to the Financial Statements for additional information. |
(b) | 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 |
|
|
|
|
Operating and Maintenance Expense for Regulatory Required Programs
Operating and maintenance expense 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 approved regulated rates. 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 nine months ended September 30, 2011March 31, 2012 compared to the same periodsperiod in 2010,2011 primarily due to higher plant balances.balances and amortization of the regulatory assets recorded in December 2011 to defer significant storm costs pursuant to EIMA.
Taxes Other Than Income
Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010.Taxes other than income taxes decreased during the three months ended September 30, 2011March 31, 2012 compared to the same period in 2010 as a result of decreased franchise and Illinois utility distribution taxes due to lower volumes delivered in 2011.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. Taxes other than income, which can vary period to period, include municipal and state utility taxes, increased during the nine ended September 30, 2011 compared to the same period in 2010 primarily reflecting the accrual of estimated future refunds of Illinois utility distribution tax recorded in the second quarter of 2010 for the 2008real estate taxes, and 2009 tax years. Previously, ComEd had recorded refunds of the Illinois utility distribution tax when received. Due to sufficient, reliable evidence, ComEd began in June 2010 recording an estimated receivable associated with anticipated Illinois utility distribution tax refunds prospectively.payroll taxes.
Interest Expense, net
Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010.Interest expense increaseddecreased during the three months ended September 30, 2011March 31, 2012 compared to the same period in 20102011 primarily due to higherfavorable interest rates on outstanding long-term debt balances.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. Interest expense decreased during the nine months ended September 30, 2011 compared to the same period in 2010 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 decrease was partially offset by higher interest expense associated with higher outstanding debt balances. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information.
Other, net
Other, net increased during the three and nine months ended September 30, 2011 compared to the same periods in 2010 primarily due to an increase in interest income related to uncertain income tax positions. See Note 14 of the Combined Notes to Consolidated Financial Statements for further details on the components of Other, Net.
Effective Income Tax Rate
Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010.The effective income tax rate was 35.3%41.2% for the three months ended September 30, 2011March 31, 2012 compared to 39.5%42.0% for the same period during 2010. The decrease in the effective income tax rate was primarily due to lower state income taxes resulting from a tax method change for transmission and distribution property repairs.2011. See Note 89 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010. The effective income tax rate was 36.4% for the nine months ended September 30, 2011 compared to 54.5% for the same period during 2010. The decrease in the effective income tax rate was primarily due to the remeasurement of uncertain income tax positions recorded in the second quarter of 2010 related to the 1999 sale of ComEd’s
fossil generating assets. The effective income tax rate 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 8 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
ComEd Electric Operating Statistics and Revenue Detail
Three Months Ended September 30, | % Change | Weather- Normal % Change | ||||||||||||||
Retail Deliveries to customers (in GWhs) | 2011 | 2010 | ||||||||||||||
Retail Delivery and Sales(a) | ||||||||||||||||
Residential | 8,877 | 9,361 | (5.2 | )% | (2.4 | )% | ||||||||||
Small commercial & industrial | 8,811 | 9,110 | (3.3 | )% | (2.2 | )% | ||||||||||
Large commercial & industrial | 7,494 | 7,503 | (0.1 | )% | 0.1 | % | ||||||||||
Public authorities & electric railroads | 303 | 283 | 7.1 | % | 10.5 | % | ||||||||||
|
|
|
| |||||||||||||
Total Retail | 25,485 | 26,257 | (2.9 | )% | (1.4 | )% | ||||||||||
|
|
|
| |||||||||||||
Nine Months Ended September 30, | % Change | Weather- Normal % Change | ||||||||||||||
Retail Deliveries to customers (in GWhs) | 2011 | 2010 | ||||||||||||||
Retail Delivery and Sales(a) | ||||||||||||||||
Residential | 22,108 | 22,778 | (2.9 | )% | (2.0 | )% | ||||||||||
Small commercial & industrial | 24,648 | 24,975 | (1.3 | )% | (0.7 | )% | ||||||||||
Large commercial & industrial | 21,011 | 20,991 | 0.1 | % | 0.2 | % | ||||||||||
Public authorities & electric railroads | 919 | 927 | (0.9 | )% | (0.5 | )% | ||||||||||
|
|
|
| |||||||||||||
Total Retail | 68,686 | 69,671 | (1.4 | )% | (0.8 | )% | ||||||||||
|
|
|
| |||||||||||||
As of September 30, | ||||||||||||||||
Number of Electric Customers | 2011 | 2010 | ||||||||||||||
Residential | 3,439,704 | 3,422,824 | ||||||||||||||
Small commercial & industrial | 364,917 | 361,424 | ||||||||||||||
Large commercial & industrial | 2,041 | 2,014 | ||||||||||||||
Public authorities & electric railroads | 4,801 | 5,090 | ||||||||||||||
|
|
|
| |||||||||||||
Total | 3,811,463 | 3,791,352 | ||||||||||||||
|
|
|
|
Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | |||||||||||||||||||||
Electric Revenue | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||
Retail Delivery and Sales(a) | ||||||||||||||||||||||||
Residential | $ | 1,112 | $ | 1,181 | (5.8 | )% | $ | 2,746 | $ | 2,788 | (1.5 | )% | ||||||||||||
Small commercial & industrial | 410 | 471 | (13.0 | )% | 1,177 | 1,273 | (7.5 | )% | ||||||||||||||||
Large commercial & industrial | 102 | 109 | (6.4 | )% | 288 | 306 | (5.9 | )% | ||||||||||||||||
Public authorities & electric railroads | 12 | 14 | (14.3 | )% | 38 | 48 | (20.8 | )% | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||
Total Retail | 1,636 | 1,775 | (7.8 | )% | 4,249 | 4,415 | (3.8 | )% | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||
Other Revenue(b) | 148 | 143 | 3.5 | % | 445 | 417 | 6.7 | % | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||
Total Electric Revenues | $ | 1,784 | $ | 1,918 | (7.0 | )% | $ | 4,694 | $ | 4,832 | (2.9 | )% | ||||||||||||
|
|
|
|
|
|
|
|
Retail Deliveries to customers (in GWhs) Retail Delivery and Sales(a) Residential Small commercial & industrial Large commercial & industrial Public authorities & electric railroads Total Retail Number of Electric Customers Residential Small commercial & industrial Large commercial & industrial Public authorities & electric railroads Total Electric Revenue Retail Delivery and Sales(a) Residential Small commercial & industrial Large commercial & industrial Public authorities & electric railroads Total Retail Other Revenue(b) Total Electric Revenues Three Months Ended
March 31, % Change Weather-
Normal %
Change 2012 2011 6,406 6,953 (7.9 )% (0.6 )% 7,916 8,074 (2.0 )% 1.1 % 6,703 6,819 (1.7 )% 0.9 % 325 330 (1.5 )% 4.1 % 21,350 22,176 (3.7 )% 0.5 % As of March 31, 2012 2011 3,465,669 3,454,410 365,525 364,585 2,013 1,994 4,790 5,004 3,837,997 3,825,993 Three Months Ended
March 31, 2012 2011 % Change $ 775 $ 834 (7.1 )% 348 382 (8.9 )% 100 90 11.1 % 12 14 (14.3 )% 1,235 1,320 (6.4 )% 153 146 4.8 % $ 1,388 $ 1,466 (5.3 )%
(a) | Reflects delivery |
(b) | Other revenue primarily includes transmission revenue from PJM. Other items include rental |
Results of Operations — PECO
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2012 | 2011 | |||||||||||||||||||||||||||||||
Operating revenues | $ | 946 | $ | 1,495 | $ | (549 | ) | $ | 2,942 | $ | 4,220 | $ | (1,278 | ) | $ | 875 | $ | 1,153 | $ | (278 | ) | |||||||||||||||
Purchased power and fuel | 464 | 673 | 209 | 1,506 | 1,987 | 481 | 411 | 633 | 222 | |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Revenue net of purchased power and fuel(a) | 482 | 822 | (340 | ) | 1,436 | 2,233 | (797 | ) | 464 | 520 | (56 | ) | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Other operating expenses | ||||||||||||||||||||||||||||||||||||
Operating and maintenance | 203 | 176 | (27 | ) | 543 | 507 | (36 | ) | 203 | 206 | 3 | |||||||||||||||||||||||||
Operating and maintenance for regulatory required programs | 16 | 15 | (1 | ) | 54 | 36 | (18 | ) | ||||||||||||||||||||||||||||
Depreciation and amortization | 51 | 326 | 275 | 150 | 859 | 709 | 53 | 48 | (5 | ) | ||||||||||||||||||||||||||
Taxes other than income | 59 | 90 | 31 | 165 | 240 | 75 | 31 | 56 | 25 | |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Total other operating expenses | 329 | 607 | 278 | 912 | 1,642 | 730 | 287 | 310 | 23 | |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Operating income | 153 | 215 | (62 | ) | 524 | 591 | (67 | ) | 177 | 210 | (33 | ) | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Other income and deductions | ||||||||||||||||||||||||||||||||||||
Interest expense, net | (34 | ) | (38 | ) | 4 | (102 | ) | (160 | ) | 58 | (31 | ) | (34 | ) | 3 | |||||||||||||||||||||
Other, net | 3 | 3 | — | 11 | 6 | 5 | 2 | 6 | (4 | ) | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Total other income and deductions | (31 | ) | (35 | ) | 4 | (91 | ) | (154 | ) | 63 | (29 | ) | (28 | ) | (1 | ) | ||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Income before income taxes | 122 | 180 | (58 | ) | 433 | 437 | (4 | ) | 148 | 182 | (34 | ) | ||||||||||||||||||||||||
Income taxes | 17 | 53 | 36 | 119 | 134 | 15 | 51 | 56 | 5 | |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Net income | 105 | 127 | (22 | ) | 314 | 303 | 11 | 97 | 126 | (29 | ) | |||||||||||||||||||||||||
Preferred security dividends | 1 | 1 | — | 3 | 3 | — | 1 | 1 | — | |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Net income on common stock | $ | 104 | $ | 126 | $ | (22 | ) | $ | 311 | $ | 300 | $ | 11 | $ | 96 | $ | 125 | $ | (29 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
(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 decrease in net income for the three months ended September 30, 2011 compared to the same period in 2010was driven primarily related to increased storm costs and the net impact of 2010 CTC recoveries reflected in electricby decreased operating revenuesrevenue net of purchased power and fuel expense due to unfavorable weather and CTC amortization expense, both ofa decline in load, which ceased at the end of the transition period on December 31, 2010. These decreases in net income werewas partially offset by the
new distribution rates effective January 1, 2011 as a result of the 2010 electricdecreased operating and natural gas rate case settlements, decreased bad debtmaintenance, taxes other than income and interest expenses. The decrease in operating and maintenance expense as well as decreased income tax expense reflecting the impact of electing the safe harbor method of tax accounting for electric transmission and distribution property. See Note 8 of the Combined Notes to the Consolidated Financial Statements for further discussion of the election of the safe harbor method.
The increase in net income for the nine months ended September 30, 2011 compared to the same period in 2010is primarily related to the new distribution rates, decreased interest expense related to the retirement of the PETT transition bonds on September 1, 2010 and the impact of the change in measurement of uncertain tax positions in the second quarter of 2010, and decreased income tax expense related to the election of the safe harbor method. These increases in net income were partially offset by increasedlower storm costs and the net impact of 2010 CTC recoveries reflected in electric operating revenues net of purchased power expense and CTC amortization expense, both of which ceased at the end of the transition period on December 31, 2010.costs.
Operating Revenues, Purchased Power and Fuel Expense
There are certain drivers to operating revenuesrevenue that are offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and customer choice programs. PECO’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 commodity procurement costs. PECO’s electric generationsupply and natural gas cost rates charged to customers are subject to adjustments at least quarterly that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC’s GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and gas revenue net of purchased power and fuel expense.
Electric and gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the customer choice program.Customer Choice Program. All PECO customers have the choice to purchase energyelectricity and gas from a competitive electric generation supplier.and natural gas suppliers, respectively. The customercustomer’s choice of electric generation suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energyelectricity and natural gas service. Customer choice program activity has no impact on electric and gas revenue net income.of purchased power and fuel expense. The number of retail customers purchasing energyelectricity from a competitive electric generation supplier was 351,532416,600 and 21,475233,200 at September 30,March 31, 2012 and 2011, and 2010, respectively, representing 22% and 1% of total retail customers, respectively. Retail deliveries purchased from competitive electric generation suppliers represented 60%64% and 54%48% of PECO’s retail kWh sales for the three and nine months ended September 30,March 31, 2012 and 2011, respectively compared to 1%respectively. The number of retail customers purchasing natural gas from a competitive natural gas supplier was 34,900 and 9,200 at March 31, 2012 and 2011, respectively. Retail deliveries purchased from competitive natural gas suppliers represented 35% and 30% of PECO’s retail mmcf sales for the three and nine months ended September 30, 2010.March 31, 2012 and 2011, respectively.
The changes in PECO’s operating revenues net of purchased power and fuel expense for the three months ended September 30, 2011March 31, 2012 compared to the same period in 20102011, consisted of the following:
Increase (Decrease) | ||||||||||||
Electric | Gas | Total | ||||||||||
Weather | $ | (9 | ) | $ | (1 | ) | $ | (10 | ) | |||
Volume | 1 | 1 | 2 | |||||||||
CTC recoveries | (351 | ) | — | (351 | ) | |||||||
Regulatory program cost recovery | 1 | — | 1 | |||||||||
Pricing | 29 | 2 | 31 | |||||||||
Other | (14 | ) | 1 | (13 | ) | |||||||
|
|
|
|
|
| |||||||
Total increase (decrease) | $ | (343 | ) | $ | 3 | $ | (340 | ) | ||||
|
|
|
|
|
|
The changes in PECO’s operating revenues net of purchased power and fuel expense for the nine months ended September 30, 2011 compared to the same period in 2010 consisted of the following:
Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||||
Electric | Gas | Total | Electric | Gas | Total | |||||||||||||||||||
Weather | $ | (16 | ) | $ | 5 | $ | (11 | ) | $ | (20 | ) | $ | (24 | ) | $ | (44 | ) | |||||||
Volume | (4 | ) | 1 | (3 | ) | (9 | ) | 1 | (8 | ) | ||||||||||||||
CTC recoveries | (906 | ) | — | (906 | ) | |||||||||||||||||||
Regulatory program cost recovery | 20 | — | 20 | |||||||||||||||||||||
Pricing | 104 | 12 | 116 | 4 | 2 | 6 | ||||||||||||||||||
Customer mix | 11 | 1 | 12 | |||||||||||||||||||||
Regulatory required programs | (2 | ) | — | (2 | ) | |||||||||||||||||||
Other | (26 | ) | 1 | (25 | ) | (9 | ) | 1 | (8 | ) | ||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total increase (decrease) | $ | (817 | ) | $ | 20 | $ | (797 | ) | ||||||||||||||||
Total decrease | $ | (36 | ) | $ | (20 | ) | $ | (56 | ) | |||||||||||||||
|
|
|
|
|
|
Weather
.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 months ended September 30, 2011 compared to the same period in 2010, electric operatingOperating revenues net of purchased power and fuel expense were lower due to the impact of unfavorable 2012 weather conditions during the third quarter of 2011 in PECO’s service territory compared to the same period in 2010.
During the nine months ended September 30, 2011 compared to the same period in 2010, electric operating revenues net of purchased power expense were lower due to unfavorable weather conditions during the second and third quarters of 2011 in PECO’s service territory compared to the same periods in 2010 despite setting a new record for highest peak load experienced to date of 8,983 MWs on July 22, 2011. Gas revenues net of fuel expense were higher due to favorable weather conditions in the first quarter of 2011 in PECO’s service territory.
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 nine months ended September 30, 2011March 31, 2012 compared to the same periodsperiod in 2010 and normal weather2011 consisted of the following:
% Change | % Change | |||||||||||||||||||||||||||||||||||||||
Heating and Cooling Degree-Days | 2011 | 2010 | Normal | From 2010 | From Normal | 2012 | 2011 | Normal | From 2011 | From Normal | ||||||||||||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 18 | — | 36 | n/a | (50.0 | )% | 1,914 | 2,506 | 2,476 | (23.6 | )% | (22.7 | )% | |||||||||||||||||||||||||||
Cooling Degree-Days | 1,109 | 1,212 | 939 | (8.5 | )% | 18.1 | % | 4 | — | — | n/a | % | n/a | % | ||||||||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 2,855 | 2,710 | 3,004 | 5.4 | % | (5.0 | )% | |||||||||||||||||||||||||||||||||
Cooling Degree-Days | 1,603 | 1,798 | 1,271 | (10.8 | )% | 26.1 | % |
Volume
.The decrease in electric operating revenues net of purchased power expense related to delivery volume, exclusive of the effects of weather, for the ninethree months ended September 30, 2011March 31, 2012 compared to the same periodperiods in 20102011 reflected the ramp-down of three oil refineries and the impact of energy efficiency initiatives and weak economic conditions on customer usage. The decrease was partially offset by additional volumes from the leap year. See Note 34 of the Combined Notes to the Consolidated Financial Statements for further information.
CTC RecoveriesPricing.
The decrease in electric revenues net of purchased power expense related to CTC recoveries for the three and nine months ended September 30, 2011 compared to the same periods in 2010 reflected the absence of the CTC charge component that was included in rates charged to customers in 2010. PECO fully recovered all stranded costs during the final year of the transition period that expired on December 31, 2010.
Regulatory Program Cost Recovery
The increase in electric revenues net of purchased power expense relating to regulatory program cost recovery for the three and nine months ended September 30, 2011 compared to the same periods in 2010 primarily related to increased recovery of costs on the energy efficiency and smart meter programs as well as administrative costs for the GSA and AEPS programs that began January 1, 2011. There are equal and offsetting expenses included in operating and maintenance for regulatory required programs, depreciation and amortization expense, and income taxes.
Pricing
The increase in operating revenues net of purchased power and fuel expense as a result of pricing reflected higher average rates due to decreased usage per customer across all customer classes. This was partially offset by the refund of the tax cash benefit resulting from the adoption of the safe harbor method of tax accounting for the three and nine months ended September 30, 2011 compared to the same periodselectric distribution property in 2010 primarily2011. The refund was reflected theon customer bills as a credit beginning January 1, 2012. The impact of the new electric and natural gas distribution rates charged to customers that became effective January 1, 2011refund is completely offset by regulatory liability amortization recorded in accordance with the 2010 PAPUC approved electric and natural gas distribution rate case settlements.income tax expense. See Note 34 of the Combined Notes to the Consolidated Financial Statements for further information.
Customer MixRegulatory Required Programs. This represents the change in operating revenues collected under approved riders to recover costs incurred for the smart meter and energy efficiency programs as well as administrative costs for the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.
Other. The increasedecrease in operatingother electric revenues net of purchased power and fuel expense as a result of customer mix for the nine months ended September 30, 2011 compared to the same period in 2010, reflected an increase in revenues associated with volume shifts among customer classes, which resulted in a different profile of rates as different customer classes are charged different rates.
Other
The decrease in electric operating revenues net of purchased power expense for the three and nine months ended September 30, 2011 compared to the same periods in 2010 primarily reflected a decrease in GRT revenue as a result of lower retail transmission and supplied energy service revenueand retail transmission revenues earned by PECO due to increased participation in the customer choice program.program and a reduction in the GRT rate. There is an equal and offsetting decrease in GRT expense included in taxes other than income. This decrease was partially offset by an increase in wholesale transmission revenue earned by PECO as a transmission owner for the use of PECO’s transmission facilities in PJM. The rates charged for wholesale transmission are based on the prior year’s peak, and the peak in 2010 was higher than in 2009.
Operating and Maintenance Expense
Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2012 | 2011 | |||||||||||
Operating and Maintenance Expense — Baseline | $ | 184 | $ | 186 | $ | (2 | ) | |||||
Operating and Maintenance Expense — Regulatory Required | ||||||||||||
Programs(a) | 19 | 20 | (1 | ) | ||||||||
|
|
|
|
|
| |||||||
Total Operating and Maintenance Expense | 203 | 206 | (3 | ) | ||||||||
|
|
|
|
|
|
(a) | 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 approved regulated rates. An equal and offsetting amount has been reflected in operating revenues. |
The increasechanges in operating and maintenance expense for the three and nine months ended September 30, 2011March 31, 2012 compared to the same period in 2010,2011, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Labor, other benefits, contracting and materials | $ | 6 | $ | 28 | ||||
Storm-related costs | 25 | 10 | ||||||
Uncollectible accounts expense | (7 | ) | (1 | ) | ||||
2010 Non-Cash Charge Resulting from Health Care Legislation | — | (2 | ) | |||||
Other | 3 | 1 | ||||||
|
|
|
| |||||
Increase in operating and maintenance expense | $ | 27 | $ | 36 | ||||
|
|
|
|
Baseline Labor, other benefits, contracting and materials Storm-related costs Uncollectible accounts expense Pension benefits Severance Other Regulatory Required Programs Smart Meter Energy Efficiency GSA Decrease in operating and maintenance expense Storm-related costs Increase
(Decrease) $ (2 ) (9 ) (2 ) 3 6 2 (2 ) 3 (3 ) (1 ) (1 ) $ (3 )
On August 27, 2011, Hurricane Irene hit PECO’s service territory interrupting electric service to approximately 500,000 customers. PECO restored power to 99% of customers within 72 hours of the storm. Hurricane Irene ranks as one of the top five worst storms in PECO history.
Operating and Maintenance for Regulatory Required Programs
Operating and maintenance expenses related to regulatory required programs consists 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. The increase in operating and maintenance for regulatory required programs during the three months ended September 30, 2011 compared to the same period in 2010 primarily reflected $3 million related to smart meter programs and $1 million related to GSA administrative costs partially offset by a $3 million decrease related to energy efficiency programs. The increase in operating and maintenance for regulatory required programs during the nine months ended September 30, 2011 compared to the same period in 2010 reflected $7 million related to smart meter programs, $3 million related to GSA administrative costs and an increase of $8 million related to energy efficiency programs. See Note 3 of the Combined Notes to the Consolidated Financial Statements for further information.
Depreciation and Amortization Expense
The decreaseincrease in depreciation and amortization expense for the three and nine months ended September 30, 2011March 31, 2012 compared to the same periodsperiod in 20102011 was primarily due to a decrease in the CTC amortization of $281 million and $725 million, respectively, which was fully amortized as of December 31, 2010.ongoing capital expenditures.
Taxes Other Than Income
The decrease in taxesTaxes other than income decreased for the three and nine months ended September 30, 2011March 31, 2012 compared to the same periodsperiod in 2010 was2011 primarily due to decreased GRT collections as a result of lower revenues.revenues and a reduction in the GRT rate. An equal and offsetting decrease in GRT revenue has been reflected in operating revenues during the current periods.period. The decrease in taxes other than income also reflects a sales and use tax reserve adjustment resulting from the completion of the audit of tax years 2005 through 2010.
Interest Expense, Net
The decrease in interest expense, net for the ninethree months ended September 30, 2011March 31, 2012 compared to the same period in 20102011 was primarily due to decreasedlower interest expense as a result of the debt retirement of PETT transition bonds on September 1, 2010 and the impact of interest expense incurred in June 2010 related to the change in measurement of uncertain tax positions in accordance with accounting guidance.November 2011.
Other, Net
The increasedecrease in other,Other, net for the ninethree months ended September 30, 2011March 31, 2012 compared to the same period in 2010 primarily related2011 was due to increased investment income and AFUDC — Equity.decreased AFUDC-Equity. See Note 16 of the Combined Notes to the Consolidated Financial Statements for further details of the components of Other, net.
Effective Income Tax Rate
PECO’s effective income tax rate was 13.9% and 29.4%34.5% for the three months ended September 30, 2011 and 2010, respectively, and 27.5% and 30.7%March 31, 2012 as compared to 30.8% for the nine months ended September 30, 2011 and 2010, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2011 compared to the same periods in 2010 primarily related to the impact of electing the safe harbor method of tax accounting for electric transmission and distribution property.period during 2011. See Note 89 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
PECO’s electric sales statistics and revenue detail were as follows:
Retail Deliveries to customers (in | Three Months Ended September 30, | % Change | Weather- Normal % Change | Nine Months Ended September 30, | % Change | Weather- Normal % Change | ||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||||
Retail Delivery and Sales(a) | ||||||||||||||||||||||||||||||||
Residential | 4,085 | 4,144 | (1.4 | )% | 2.1 | % | 10,750 | 10,789 | (0.4 | )% | 1.9 | % | ||||||||||||||||||||
Small commercial & industrial | 2,272 | 2,368 | (4.1 | )% | (3.2 | )% | 6,437 | 6,545 | (1.7 | )% | (1.0 | )% | ||||||||||||||||||||
Large commercial & industrial | 4,370 | 4,447 | (1.7 | )% | (0.6 | )% | 12,012 | 12,397 | (3.1 | )% | (2.2 | )% | ||||||||||||||||||||
Public authorities & electric railroads | 239 | 228 | 4.8 | % | 6.4 | % | 710 | 699 | 1.6 | % | 3.3 | % | ||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total Electric Retail | 10,966 | 11,187 | (2.0 | )% | (0.1 | )% | 29,909 | 30,430 | (1.7 | )% | (0.4 | )% | ||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
As of September 30, | ||||||||||||||||||||||||||||||||
Number of Electric Customers | 2011 | 2010 | ||||||||||||||||||||||||||||||
Residential | 1,412,070 | 1,408,239 | ||||||||||||||||||||||||||||||
Small commercial & industrial | 156,769 | 156,502 | ||||||||||||||||||||||||||||||
Large commercial & industrial | 3,116 | 3,092 | ||||||||||||||||||||||||||||||
Public authorities & electric railroads | 1,123 | 984 | ||||||||||||||||||||||||||||||
|
|
|
| |||||||||||||||||||||||||||||
Total | 1,573,078 | 1,568,817 | ||||||||||||||||||||||||||||||
|
|
|
|
Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | |||||||||||||||||||||
Electric Revenue | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||
Retail Delivery and Sales (a) | ||||||||||||||||||||||||
Residential | $ | 598 | $ | 663 | (9.8 | )% | $ | 1,542 | $ | 1,625 | (5.1 | )% | ||||||||||||
Small commercial & industrial | 138 | 308 | (55.2 | )% | 471 | 827 | (43.0 | )% | ||||||||||||||||
Large commercial & industrial | 84 | 374 | (77.5 | )% | 259 | 1,035 | (75.0 | )% | ||||||||||||||||
Public authorities & electric railroads | 9 | 20 | (55.0 | )% | 29 | 67 | (56.7 | )% | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||
Total Retail | 829 | 1,365 | (39.3 | )% | 2,301 | 3,554 | (35.3 | )% | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||
Other Revenue | 62 | 74 | (16.2 | )% | 186 | 194 | (4.1 | )% | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||
Total Electric Revenues | $ | 891 | $ | 1,439 | (38.1 | )% | $ | 2,487 | $ | 3,748 | (33.6 | )% | ||||||||||||
|
|
|
|
|
|
|
|
Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||
Retail Deliveries to customers (in GWhs) | 2012 | 2011 | ||||||||||||||
Retail Deliveries and Sales(a) | ||||||||||||||||
Residential | 3,166 | 3,590 | (11.8 | )% | (2.5 | )% | ||||||||||
Small commercial & industrial | 1,951 | 2,144 | (9.0 | )% | (4.9 | )% | ||||||||||
Large commercial & industrial | 3,637 | 3,691 | (1.5 | )% | (1.8 | )% | ||||||||||
Public authorities & electric railroads | 237 | 242 | (2.1 | )% | (2.1 | )% | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total Electric Retail | 8,991 | 9,667 | (7.0 | )% | (2.7 | )% | ||||||||||
|
|
|
|
|
|
|
|
As of March 31, | ||||||||
Number of Electric Customers | 2012 | 2011 | ||||||
Residential | 1,420,734 | 1,414,103 | ||||||
Small commercial & industrial | 157,322 | 156,759 | ||||||
Large commercial & industrial | 3,109 | 3,096 | ||||||
Public authorities & electric railroads | 1,122 | 1,081 | ||||||
|
|
|
| |||||
Total | 1,582,287 | 1,575,039 | ||||||
|
|
|
|
Electric Revenue Retail Deliveries and Sales(a) Residential Small commercial & industrial Large commercial & industrial Public authorities & electric railroads Total Electric Retail Other revenue(b) Total Electric Revenues Three Months Ended
March 31, % Change 2012 2011 $ 407 $ 493 (17.4 )% 118 169 (30.2 )% 53 108 (50.9 )% 8 11 (27.3 )% 586 781 (25.0 )% 57 63 (9.5 )% $ 643 $ 844 (23.8 )%
(a) | Reflects delivery |
(b) | Other revenue includes transmission revenue from PJM and wholesale electric revenues. |
PECO Gas OperatingSales Statistics and Revenue Detail
PECO’s gas sales statistics and revenue detail were as follows:
Deliveries to customers (in mmcf) | Three Months Ended September 30, | % Change | Weather- Normal % Change | Nine Months Ended September 30, | % Change | Weather- Normal % Change | ||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||||
Retail Delivery and Sales(b) | ||||||||||||||||||||||||||||||||
Retail sales | 3,687 | 3,546 | 4.0 | % | 7.2 | % | 38,982 | 37,103 | 5.1 | % | 0.9 | % | ||||||||||||||||||||
Transportation and other | 6,190 | 8,501 | (27.2 | )% | (29.1 | )% | 21,428 | 23,658 | (9.4 | )% | (8.4 | )% | ||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total Gas Deliveries | 9,877 | 12,047 | (18.0 | )% | (18.5 | )% | 60,410 | 60,761 | (0.6 | )% | (2.5 | )% | ||||||||||||||||||||
|
|
|
|
|
|
|
|
As of September 30, | ||||||||
Number of Gas Customers | 2011 | 2010 | ||||||
Residential | 448,763 | 446,348 | ||||||
Commercial & industrial | 40,883 | 40,863 | ||||||
|
|
|
| |||||
Total Retail | 489,646 | 487,211 | ||||||
Transportation | 868 | 834 | ||||||
|
|
|
| |||||
Total | 490,514 | 488,045 | ||||||
|
|
|
|
Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||
Deliveries to customers (in mmcf) | 2012 | 2011 | ||||||||||||||
Retail Deliveries and Sales | ||||||||||||||||
Retail sales(a) | 22,427 | 28,734 | (21.9 | )% | 1.3 | % | ||||||||||
Transportation and other | 7,766 | 8,960 | (13.3 | )% | (11.2 | )% | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total Gas Deliveries | 30,193 | 37,694 | (19.9 | )% | (1.6 | )% | ||||||||||
|
|
|
|
|
|
|
|
Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | |||||||||||||||||||||
Gas revenue | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||
Retail Delivery and Sales(b) | ||||||||||||||||||||||||
Retail sales | $ | 50 | $ | 52 | (3.8 | )% | $ | 428 | $ | 451 | (5.1 | )% | ||||||||||||
Transportation and other | 5 | 4 | 25.0 | % | 27 | 21 | 28.6 | % | ||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||
Total Gas Deliveries | $ | 55 | $ | 56 | (1.8 | )% | $ | 455 | $ | 472 | (3.6 | )% | ||||||||||||
|
|
|
|
|
|
|
|
As of March 31, | ||||||||
Number of Gas Customers | 2012 | 2011 | ||||||
Residential | 452,800 | 449,398 | ||||||
Commercial & industrial | 41,577 | 41,254 | ||||||
|
|
|
| |||||
Total Retail | 494,377 | 490,652 | ||||||
Transportation | 888 | 857 | ||||||
|
|
|
| |||||
Total | 495,265 | 491,509 | ||||||
|
|
|
|
Three Months Ended March 31, | % Change | |||||||||||
Gas revenue | 2012 | 2011 | ||||||||||
Retail sales | $ | 222 | $ | 296 | (25.0 | )% | ||||||
Transportation and other | 10 | 13 | (23.1 | )% | ||||||||
|
|
|
|
|
| |||||||
Total Gas Revenue | $ | 232 | $ | 309 | (24.9 | )% | ||||||
|
|
|
|
|
|
Reflects delivery |
Results of Operations — BGE
Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||
2012 | 2011 | |||||||||||
Operating revenues | $ | 696 | $ | 976 | $ | (280 | ) | |||||
Purchased power and fuel expense | 385 | 544 | 159 | |||||||||
|
|
|
|
|
| |||||||
Revenue net of purchased power and fuel expense(a) | 311 | 432 | (121 | ) | ||||||||
|
|
|
|
|
| |||||||
Other operating expenses | ||||||||||||
Operating and maintenance | 195 | 152 | (43 | ) | ||||||||
Depreciation and amortization | 79 | 77 | (2 | ) | ||||||||
Taxes other than income | 48 | 50 | 2 | |||||||||
|
|
|
|
|
| |||||||
Total other operating expenses | 322 | 279 | (43 | ) | ||||||||
|
|
|
|
|
| |||||||
Operating (loss) income | (11 | ) | 153 | (164 | ) | |||||||
|
|
|
|
|
| |||||||
Other income and deductions | ||||||||||||
Interest expense, net | (41 | ) | (33 | ) | (8 | ) | ||||||
Other, net | 6 | 8 | (2 | ) | ||||||||
|
|
|
|
|
| |||||||
Total other income and deductions | (35 | ) | (25 | ) | (10 | ) | ||||||
|
|
|
|
|
| |||||||
(Loss) Income before income taxes | (46 | ) | 128 | (174 | ) | |||||||
Income taxes | (16 | ) | 47 | 63 | ||||||||
|
|
|
|
|
| |||||||
Net (loss) income | (30 | ) | 81 | (111 | ) | |||||||
Preference stock dividends | 3 | 3 | — | |||||||||
|
|
|
|
|
| |||||||
Net (loss) income on common stock | $ | (33 | ) | $ | 78 | $ | (111 | ) | ||||
|
|
|
|
|
|
(a) | BGE 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. BGE believes revenue net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power and 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 decrease in net income was driven primarily by decreased operating revenue net of purchased power and fuel expense related to the accrual of the residential customer rate credit to be provided as a condition of the MDPSC’s approval of Exelon’s merger with Constellation. The decrease in net income was also driven by increased operating and maintenance expenses, primarily related to BGE’s accrual of its portion of the charitable contributions to be provided as a condition of the MDPSC’s approval of the merger as well as merger transaction costs — these costs are not recoverable from BGE’s customers.
Operating Revenues, Purchased Power and Fuel Expense
There are certain drivers to operating revenue that are offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Electric and gas revenues and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.
The number of customers electing to select a competitive electric supplier affects electric SOS revenues and purchased power expense. The number of customers electing to select a competitive natural gas supplier affects gas cost adjustment revenues and purchased natural gas expense. All BGE customers have the choice to purchase energy from a competitive electric supplier. This customer choice of electric suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to SOS. The number of retail customers purchasing electricity from a competitive electric supplier was 320,800 and 258,300 at March 31, 2012 and 2011, respectively, representing 26% and 21% of total retail customers, respectively. Retail deliveries purchased from competitive electric suppliers represented 62% and 52% of BGE’s retail kWh sales for the three months ended March 31, 2012 and 2011, respectively. The number of retail customers purchasing natural gas from a competitive natural gas supplier was 118,200 and 96,600 at March 31, 2012 and 2011, respectively, representing 18% and 15% of total retail customers, respectively. Retail deliveries purchased from competitive natural gas suppliers represented 55% and 45% of BGE’s retail mmcf sales for the three months ended March 31, 2012 and 2011, respectively.
The changes in BGE’s operating revenues net of purchased power and fuel expense for the three months ended March 31, 2012 compared to the same period in 2011, consisted of the following:
Increase (Decrease) | ||||||||||||
Electric | Gas | Total | ||||||||||
Residential customer rate credit(a) | $ | (82 | ) | $ | (31 | ) | $ | (113 | ) | |||
Regulatory required programs | — | 2 | 2 | |||||||||
Other | (1 | ) | (9 | ) | (10 | ) | ||||||
|
|
|
|
|
| |||||||
Total increase (decrease) | $ | (83 | ) | $ | (38 | ) | $ | (121 | ) | |||
|
|
|
|
|
|
(a) | In accordance with the MDPSC order approving Exelon’s merger with Constellation, the residential customer rate credit is not recoverable from BGE’s customers. Exelon will make a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction. |
Revenue Decoupling. The demand for electricity and gas is affected by weather and usage conditions. The MDPSC has allowed BGE to record a monthly adjustment to its electric and gas distribution revenues from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE’s electric and gas distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at MDPSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. BGE bills or credits impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.
Volume. Heating degree days are quantitative indices that reflect the demand for energy needed to heat a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in BGE’s service territory. The changes in heating degree days in BGE’s service territory for the three months ended March 31, 2012 compared to the same period in 2011 consisted of the following:
% Change | ||||||||||||||||||||
Heating Degree-Days | 2012 | 2011 | Normal | From 2011 | From Normal | |||||||||||||||
Heating Degree-Days | 1,874 | 2,449 | 2,413 | (23.5 | )% | (22.3 | )% |
Residential Customer Rate Credit. The accrual of the residential customer rate credit to be provided as a result of the MDPSC’s review and approval of Exelon’s merger with Constellation decreased operating revenues net of purchased power and fuel expense.
Regulatory Required Programs. This represents the change in revenues collected under approved riders to recover costs incurred for the energy efficiency and demand response programs as well as administrative and commercial and industrial customer bad debt costs for SOS. The riders are designed to provide full recovery, as well as a return in certain instances. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and taxes other than income taxes. The increase in revenues during the three months ended March 31, 2012 compared to the same period in 2011 was due to the recovery of higher energy efficiency program costs.
Other. Other revenues decreased during the three months ended March 31, 2012 compared to the same period in 2011. Other revenues, which can vary from period to period, include commodity revenues which are affected by the number of customers using competitive suppliers as well as the cost of purchased power and natural gas. Other revenues also include transmission revenues and other miscellaneous revenues such as late payment charge revenues.
Operating and Maintenance Expense
Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2012 | 2011 | |||||||||||
Operating and Maintenance Expense — Baseline | $ | 195 | $ | 152 | $ | 43 | ||||||
Operating and Maintenance Expense — Regulatory Required Programs(a) | — | — | — | |||||||||
|
|
|
|
|
| |||||||
Total Operating and Maintenance Expense | 195 | 152 | 43 | |||||||||
|
|
|
|
|
|
(a) | 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 approved regulated rates. An equal and offsetting amount has been reflected in operating revenues. |
The changes in operating and maintenance expense for the three months ended March 31, 2012 compared to the same period in 2011, consisted of the following:
Increase (Decrease) | ||||
Baseline | ||||
Charitable contributions accrual(a) | $ | 28 | ||
Storm costs deferral(b) | 16 | |||
Merger transaction costs(a) | 12 | |||
Storm-related costs | (14 | ) | ||
Labor, other benefits, contracting and materials | (5 | ) | ||
Other | 6 | |||
|
| |||
43 | ||||
Regulatory Required Programs | ||||
SOS | — | |||
|
| |||
Increase in operating and maintenance expense | $ | 43 | ||
|
|
(a) | In accordance with the MDPSC order approving Exelon’s merger with Constellation, the charitable contribution accrual and merger transaction costs are not recoverable from BGE’s customers. |
(b) | During the first quarter of 2011, the MDPSC issued a comprehensive rate order permitting the deferral of incremental distribution service restoration expenses associated with 2010 storms as a regulatory asset. |
Depreciation and Amortization
The increase in depreciation and amortization expense for the three months ended March 31, 2012 compared to the same period in 2011 was primarily due to higher plant balances. Additionally, depreciation and amortization expense includes amortization expense related to energy efficiency and demand response programs which is fully offset in revenues above.
Taxes Other Than Income
Taxes other than income decreased for the three months ended March 31, 2012 compared to the same period in 2011 primarily due to decreased gross receipts tax as a result of lower revenues.
Interest Expense, Net
The increase in interest expense, net for the three months ended March 31, 2012 compared to the same period in 2011 was primarily due to interest recorded on prior year tax liabilities as well as higher outstanding debt balances.
Other, Net
Other, net remained relatively level in the three months ended March 31, 2012 compared to the same period in 2011. See Note 16 of the Combined Notes to Consolidated Financial Statements for further details of the components of Other, net.
Effective Income Tax Rate
BGE’s effective income tax rate was 34.8% for the three months ended March 31, 2012 as compared to 36.7% for the same period during 2011. See Note 9 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in effective income tax rate.
BGE Electric Operating Statistics and Revenue Detail
BGE’s electric sales statistics and revenue detail were as follows:
Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||
Retail Deliveries to customers (in GWhs) | 2012 | 2011 | ||||||||||||||
Retail Deliveries and Sales(a) | ||||||||||||||||
Residential | 3,201 | 3,524 | (9.2 | )% | n.m. | |||||||||||
Small commercial & industrial | 711 | 810 | (12.2 | )% | n.m. | |||||||||||
Large commercial & industrial | 3,639 | 3,629 | 0.3 | % | n.m. | |||||||||||
Public authorities & electric railroads | 106 | 120 | (11.7 | )% | n.m. | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total Electric Retail | 7,657 | 8,083 | (5.3 | )% | n.m. | |||||||||||
|
|
|
|
|
|
|
|
As of March 31, | ||||||||
Number of Electric Customers | 2012 | 2011 | ||||||
Residential | 1,116,201 | 1,116,537 | ||||||
Small commercial & industrial | 113,177 | 112,333 | ||||||
Large commercial & industrial | 11,492 | 11,542 | ||||||
Public authorities & electric railroads | 298 | 326 | ||||||
|
|
|
| |||||
Total | 1,241,168 | 1,240,738 | ||||||
|
|
|
|
Electric Revenue Retail Deliveries and Sales(a) Residential Small commercial & industrial Large commercial & industrial Public authorities & electric railroads Total Electric Retail Other revenue Total Electric Revenues Three Months Ended
March 31, % Change 2012 2011 $ 265 $ 423 (37.4 )% 58 70 (17.1 )% 96 106 (9.4 )% 13 13 — % 432 612 (29.4 )% 57 57 — % $ 489 $ 669 (26.9 )%
(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from BGE and customers electing to receive electric generation service from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission. |
BGE Gas Sales Statistics and Revenue Detail
BGE’s gas sales statistics and revenue detail were as follows:
Deliveries to customers (in mmcf) | Three Months Ended March 31, | % Change | Weather - Normal % Change | |||||||||||||
2012 | 2011 | |||||||||||||||
Retail sales | 33,931 | 42,078 | (19.4 | )% | n.m. | |||||||||||
Transportation and other | 5,440 | 5,554 | (2.1 | )% | n.m. | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total Gas Deliveries | 39,371 | 47,632 | (17.3 | )% | n.m. | |||||||||||
|
|
|
|
|
|
|
|
As of March 31, | ||||||||
Number of Gas Customers | 2012 | 2011 | ||||||
Residential | 610,612 | 609,495 | ||||||
Commercial & industrial | 44,170 | 44,195 | ||||||
|
|
|
| |||||
Total | 654,782 | 653,690 | ||||||
|
|
|
|
Three Months Ended March 31, | % Change | |||||||||||
Gas revenue | 2012 | 2011 | ||||||||||
Retail sales | $ | 188 | $ | 271 | (30.6 | )% | ||||||
Transportation and other(b) | 19 | 36 | (47.2 | )% | ||||||||
|
|
|
|
|
| |||||||
Total Gas Revenue | $ | 207 | $ | 307 | (32.6 | )% | ||||||
|
|
|
|
|
|
(b) | Transportation and other gas revenue includes off-system revenue of 5,440 mmcfs ($17M) and 5,554 mmcfs ($32M) for the three months ended March 31, 2012 and 2011, respectively. |
Liquidity and Capital Resources
Exelon and Generation activity presented below includes the activity of Constellation, and BGE in the case of Exelon, from the merger effective date of March 12, 2012 through March 31, 2012. Exelon and Generation prior year activity is unadjusted for the effects of the merger. BGE activity presented below includes its activity for the three months ended March 31, 2012 and 2011.
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, PECO and PECOBGE have access to unsecured revolving credit facilities with aggregate bank commitments of $500 million, $5.3$3.6 billion, $1$5.6 billion, $1.0 billion, $0.6 billion and $600 million,$0.6 billion, respectively. Additionally, Generation has access to a supplemental credit facility with an aggregate available commitment of $300 million. The Registrants’ revolving credit facilities extendexpire between October 2013 and March 2017. The supplemental facilities at Exelon and Generation have expirations that range from September 2013 through March 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 PECO2016. The Registrants 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, PECO and PECOBGE 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 78 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, PECO’s and PECO’sBGE’s cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO and BGE, gas distribution services. ComEd’s, PECO’s and PECO’sBGE’s distribution services are provided to an established and diverse base of retail customers. ComEd’s, PECO’s and PECO’sBGE’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 34 and 1315 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.
Pension and Other Postretirement Benefits
The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plans. The funded status changes 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 Exelon’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 other postretirement welfarebenefit plans at September 30, 2011March 31, 2012 by updating the most significant assumptions affecting plan obligations and assets, which are the discount rate and current year’s plan asset investment performance. The discount rates for Exelon’s
Effective March 12, 2012, Exelon became the sponsor of all of Constellation’s defined benefit pension and other postretirement benefit plans. The pension plan discount rates for legacy Exelon and Constellation plans
were 4.82%4.60% and 4.89%4.42%, respectively, at September 30, 2011,March 31, 2012. The other postretirement benefit plan discount rates for legacy Exelon and 5.26%Constellation plans were 4.68% and 5.30%4.43%, respectively, at DecemberMarch 31, 2010.2012. Exelon’s pension and funded other postretirement benefit plans experienced actual asset returns of approximately 5%3.78% and (3)%6.93%, respectively, for the ninethree months ended September 30, 2011. Exelon’s $2.1 billion pension contribution in January 2011, in conjunction with its investment strategy to reduce the risk profile of its portfolio of pension assets, has partly mitigated the impact of lower discount rates on Exelon’s pension obligation. See Note 10 — Retirement Benefits for additional information on Exelon’s pension investment strategy.March 31, 2012.
Based on these assumptions, Exelon has estimated the unfunded status of the pension and other postretirement benefit plans at September 30, 2011March 31, 2012 to be $2,317$2,635 million and $2,679 million, respectively, representing a funded status percentage of 83% and 36%41%, respectively. The pension unfunded status has improved by $1,348of Exelon’s pension and other postretirement benefit plans increased $399 million and $414 million, respectively, since December 31, 20102011 primarily due to the $2.1 billionacquisition of Constellation’s pension contribution madeand other postretirement benefit plans, growth in January 2011,benefit obligations as a result of service and interest cost, a decrease in Exelon’s discount rates and demographic losses based on Exelon’s updated valuation, partially offset by favorable asset returns as of March 31, 2012. Legacy Constellation asset returns are for the decrease in discount rates from December 31, 2010. The other postretirement benefit plan unfunded status has increased by $460 million since December 31, 2010 primarily due to the decrease in discount rates from December 31, 2010.period after March 12, 2012.
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. Exelon contributed $2.1 billionexpects to contribute $100 million to its qualified pension plans in January 2011, representing substantially all currently planned 2011 qualified pension plan contributions,2012, of which Generation, ComEd and PECO contributed $952will contribute $59 million, $871$12 million and $110$16 million, respectively. Exelon funded the $2.1 billion
contribution with $500 million from cash from operations, $750 million from the tax benefits of making theLegacy Constellation’s 2011 pension contributions included an acceleration of estimated calendar year 2012 contributions. Therefore, BGE does not anticipate any qualified pension contributions in 2012. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $61 million in 2012, of which Generation, ComEd, PECO and $850BGE will make payments of $9 million, associated with the accelerated cash tax benefits from the 100% bonus depreciation provision enacted as part of the Tax Relief Act of 2010.$14 million, $1 million and $1 million, respectively.
Management has estimated its future pension contributions at September 30, 2011,March 31, 2012, incorporating currentupdated projected discount rates and actual census data for legacy Exelon plans as of January 1, 2011.2012. 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 incremental contributions Exelon may elect to make in these future periods:
2012 | 2013 | 2014 | 2015 | 2016 | Cumulative | |||||||||||||||||||
Estimated pension contributions | $ | 140 | $ | 130 | $ | 140 | $ | 725 | $ | 675 | $ | 1,810 |
2013 | 2014 | 2015 | 2016 | 2017 | Cumulative | |||||||||||||||||||
Estimated pension contributions | $ | 150 | $ | 255 | $ | 925 | $ | 700 | $ | 280 | $ | 2,310 |
To the extent interest rates continue to decline or the pension plans do not earn the expected asset return rates, (assumed at 8% as of December 31, 2010), annual pension contribution requirements in future years could increase and such increases could be significant, especially in years 20132014 and beyond.
Unlike the qualified pension plans, Exelon’s other postretirement plans are not subject to regulatory minimum contribution requirements. Management considersExelon’s management has historically considered several factors in determining the level of contributions to Exelon’sits other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery). In 2012, Exelon expects to contribute $271 million toanticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with the exception of those plans previously sponsored by Constellation and AmerGen, which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $321 million in the fourth quarter of 2011,2012, of which Generation, ComEd, PECO and PECOBGE expect to contribute $118$132 million, $105$116 million, $34 million and $28$17 million, respectively. TheThis total excludes $4 million in 2012 other postretirement benefit plan contributions by BGE prior to the closing of Exelon’s merger with Constellation on March 12, 2012. Based on the current funding strategy, the Registrants expect to contribute an aggregate of approximately $265-315$275 million - $305 million annually from 20122013 to 20162017 to the other postretirement benefit plans.
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 that2012 for the years for which there is a resulting tax deficiency. 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. Further, Exelon willexpects to receive additional tax refunds of approximately $365$350 million between 2012 and 2014. In order to stop additional interest2014, including the refund resulting from accruing on the IRS expected assessment,nuclear decommissioning trust fund special transfer tax deduction described in Note 11 of the Exelon made a payment in December 2010 to2011 Form 10-K of which approximately $50 million and $350 million would be received by Generation and ComEd, respectively, and the IRS of $302 million. During 2010,remainder paid by Exelon. Exelon and IRS Appeals have failed to reach a settlement with respect to the like-kind exchange position and the related substantial understatement penalty. See Note 89 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.
On August 19, 2011, the IRS issued Revenue Procedure 2011-43 that provides a safe harbor method of tax accounting for electric transmission and distribution property. ComEd intends to adopt the safe harbor in the Revenue Procedure in future periods as the associated tax cash benefits are received for the 2011 tax year. PECO adopted the safe harbor for the 2010 tax year. This change to the newly prescribed method will result in an initial cash tax benefit (primarily in 2011) at Exelon, ComEd and PECO in the amount of approximately $300 million, $250 million and $95 million, respectively, partially offset by a cash tax detriment at Generation in the amount of $28 million. See Note 3 of the Combined Notes to Consolidated Financial Statements for discussion of the regulatory treatment prescribed in the 2010 electric distribution rate case settlement for PECO’s cash tax benefit resulting from the application of the method change to years prior to 2010.
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, iswas eligible for 100% bonus depreciation. Additionally, qualifying property placed into service during 2012 is eligible for 50% bonus depreciation. These provisions willare expected to generate approximately $1 billion$650 million of cash for Exelon (approximately $850 million in 2011 and approximately $170 million in 2012).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, PECO and BGE generally increase future revenue requirements, the bonus depreciation associated with these capital additions will partially mitigate any future rate increases through the ratemaking process.
|
Given 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.
The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the ninethree months ended September 30, 2011March 31, 2012 and 2010:2011:
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||||||||||
2011 | 2010 | Variance | 2012 | 2011 | Variance | |||||||||||||||||||
Net income | $ | 1,889 | $ | 2,039 | $ | (150 | ) | $ | 200 | $ | 668 | $ | (468 | ) | ||||||||||
Add (subtract): | ||||||||||||||||||||||||
Non-cash operating activities(a) | 3,863 | 2,633 | 1,230 | 1,231 | 1,223 | 8 | ||||||||||||||||||
Pension and non-pension postretirement benefit contributions | (2,089 | ) | (740 | ) | (1,349 | ) | ||||||||||||||||||
Pension and other postretirement benefit contributions | (55 | ) | (2,088 | ) | 2,033 | |||||||||||||||||||
Income taxes | 532 | 310 | 222 | 178 | 733 | (555 | ) | |||||||||||||||||
Changes in working capital and other noncurrent assets and liabilities(b) | (530 | ) | (318 | ) | (212 | ) | (800 | ) | (612 | ) | (188 | ) | ||||||||||||
Option premiums received (paid), net | 59 | (101 | ) | 160 | ||||||||||||||||||||
Option premiums (paid) received, net | (100 | ) | 19 | (119 | ) | |||||||||||||||||||
Counterparty collateral received (posted), net | (807 | ) | 289 | (1,096 | ) | 340 | (150 | ) | 490 | |||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net cash flows provided by operations | $ | 2,917 | $ | 4,112 | $ | (1,195 | ) | |||||||||||||||||
Net cash flows provided by (used in) operations | $ | 994 | $ | (207 | ) | $ | 1,201 | |||||||||||||||||
|
|
|
|
|
|
(a) | Represents depreciation, amortization and accretion, impairment of long-lived assets, mark-to-market gains and losses on derivative transactions, deferred income taxes, provision for uncollectible accounts, pension and |
(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 (used in) operations for the ninethree months ended September 30,March 31, 2012 and 2011 and 2010 by Registrant were as follows:
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
2011 | 2010 | 2012 | 2011 | |||||||||||||
Exelon | $ | 2,917 | $ | 4,112 | $ | 994 | $ | (207 | ) | |||||||
Generation | 2,122 | 2,563 | 795 | 578 | ||||||||||||
ComEd | 615 | 642 | �� | 291 | (354 | ) | ||||||||||
PECO | 656 | 919 | 172 | 16 | ||||||||||||
BGE | 252 | 350 |
Changes in Exelon’s, Generation’s, ComEd’s, PECO’s and PECO’sBGE’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 ninethree months ended September 30,March 31, 2012 and 2011 and 2010 were as follows:
Generation
During the ninethree months ended September 30,March 31, 2012 and 2011, and 2010, Generation had net receipts (payments) receipts of counterparty collateral of $(804)$348 million and $443$(206) million, respectively. Net payments during the ninethree months ended September 30,March 31, 2012 and 2011 and 2010 were primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position. Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted or collected from its counterparties. This collateral may be in various forms, such as cash, which may be obtained through the issuance of commercial paper, or letters of credit.
|
During the ninethree months ended September 30,March 31, 2012 and 2011, and 2010, Generation had net (payments) collections (payments) of approximately $59$(100) million and $(101)$19 million, respectively, related to the purchasepurchases 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.
During the three months ended March 31, 2012 and 2011, Generation’s accounts receivable from PECO increased (decreased) $8 million and $(224) million, respectively. The decrease for the three months ended March 31, 2011 was due to the expiration of the PECO PPA in December 2010.
ComEd
During the ninethree months ended September 30,March 31, 2012 and 2011, and 2010, ComEd’s net payables to Generation for energy purchases related to its supplier forward contract, ICC-approved RFP contracts and financial swap contract decreasedsettlements increased (decreased) by $1$6 million and $90$(9) million, respectively. During the ninethree months ended September 30,March 31, 2012 and 2011, and 2010, ComEd’s payables to other energy suppliers for energy purchases decreased by $67$(16) million and $8$(21) million, respectively.
During the ninethree months ended September 30,March 31, 2012 and 2011, ComEd posted $6$8 million and received $56 million of incremental cash collateral towith/from PJM due to seasonal variations in its energy transmission activity levels. ComEd’s collateral posted with PJM increased during the three months ended March 31, 2012 due to the reallocation of the $50 million unsecured credit level afforded to Exelon amongst a greater number of subsidiaries following the merger with Constellation. As of September 30,March 31, 2012 and 2011, ComEd had $159$98 million and $97 million, respectively, of collateral remaining at PJM.
PECO
During the ninethree months ended September 30,March 31, 2012 and 2011, and 2010, PECO’s payables to Generation for energy purchases decreasedincreased (decreased) by $211$8 million and $16$(224) million, respectively. During the nine months ended September 30, 2011respectively, and 2010, PECO’s payables to other energyelectric and gas suppliers for energy purchases (decreased) increased by $95$(30) million and $2$59 million, respectively.
BGE
During the three months ended March 31, 2012 and 2011, BGE’s payables to Generation for energy purchases remained consistent and decreased $7 million, respectively, and payables to other electric and gas suppliers for energy purchases decreased by $10 million and $3 million, respectively.
During the ninethree months ended September 30,March 31, 2012 and 2011, and 2010, PECO’s prepaid utility taxes BGE’s accrued expenses (decreased)/increased by $40$(52) million and $31 million, respectively, primarily due to the Pennsylvania GRT prepayment in Marchreversal of each year.an accrued uncertain tax position and $61 million due to the accrual of an uncertain tax position, respectively.
Cash Flows from Investing Activities
Cash flows provided by (used in)used in investing activities for the ninethree months ended September 30,March 31, 2012 and 2011 and 2010 by Registrant were as follows:
Nine Months Ended September 30, | ||||||||
2011 | 2010 | |||||||
Exelon | $ | (4,031 | ) | $ | (2,037 | ) | ||
Generation | (2,421 | ) | (1,501 | ) | ||||
ComEd | (1,276 | ) | (670 | ) | ||||
PECO | (402 | ) | 61 |
Exelon Generation ComEd PECO BGE Three Months Ended
March 31, 2012 2011 $ (640 ) $ (1,179 ) (471 ) (823 ) (280 ) (241 ) (130 ) (172 ) (140 ) (159 )
Capital expenditures by Registrant for the ninethree months ended September 30,March 31, 2012 and 2011 and 2010 and projected amounts for the full year 20112012 are as follows:
Projected Full Year(a) | Nine Months Ended September 30, | Projected Full Year 2012 | Three Months Ended March 31, | |||||||||||||||||||||
2011 | 2011 | 2010 | 2012 | 2011 | ||||||||||||||||||||
Generation(b) | $ | 2,726 | $ | 1,865 | $ | 1,405 | ||||||||||||||||||
ComEd | 1,032 | 758 | 686 | |||||||||||||||||||||
Exelon | $ | 6,468 | $ | 1,496 | $ | 1,150 | ||||||||||||||||||
Generation(a) | 4,088 | 1,055 | 772 | |||||||||||||||||||||
ComEd(b) | 1,329 | 291 | 251 | |||||||||||||||||||||
PECO | 477 | 321 | 358 | 436 | 96 | 121 | ||||||||||||||||||
BGE | 548 | 115 | 136 | |||||||||||||||||||||
Other(c) | 41 | 28 | (67 | ) | 67 | 20 | 6 | |||||||||||||||||
|
|
| ||||||||||||||||||||||
Exelon | $ | 4,276 | $ | 2,972 | $ | 2,382 | ||||||||||||||||||
|
|
|
(a) | Includes nuclear fuel. |
(b) | The projected capital expenditures |
|
(c) | Other primarily consists of corporate operations and BSC. |
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 39%33% and 29% of the projected 20112012 capital expenditures at Generation are for investments in renewable energy generation, including Antelope Valley and Exelon Wind construction costs, and the acquisition of nuclear fuel, with therespectively. The remaining amounts primarily reflectingreflect additions and upgrades to existing facilities (includingincluding material condition improvements during nuclear refueling outages). Includedoutages. Also included in the projected 20112012 capital expenditures are a portion of the costs of a series of planned power uprates across Generation’s nuclear fleet and a portion of the Antelope Valley construction costs.fleet. See “EXELON CORPORATION — Executive Overview,” for more information on nuclear uprates.
ComEd, PECO and PECOBGE
Approximately 83%79%, 70% and 73%76% of the projected 20112012 capital expenditures at ComEd, PECO and PECO,BGE, respectively, are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and ComEd’s, PECO’s transmission system reliability upgrades required by PJM related to Generation’s plant retirements.and BGE’s construction commitments under PJM’s RTEP. The remaining amounts are for capital additions to support new business and customer growth, which for PECOComEd includes capital expenditures related to itssmart grid/smart meter technology required under EIMA, and for PECO and BGE includes capital expenditures related to their smart meter program and SGIG project, net of DOE expected reimbursements. See Note 34 of the Combined Notes to Consolidated Financial Statements for additional information.
On November 30,In 2010, NERC provided guidance to transmission owners that will requirerecommends ComEd, PECO and PECO toBGE 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. In compliance with this guidance, ComEd, PECO and BGE submitted their most recent bi-annual reports to NERC in January 2012. ComEd, PECO mayand BGE will be required to incurincurring incremental capital expenditures which may be significant at ComEd, associated with this guidance uponfollowing the completion of the assessments. Specific projects and expenditures will not beare identified untilas the assessments are completed. ComEdComEd’s, PECO’s and PECO are each continuing to evaluate their totalBGE’s forecasted 2012 capital expenditures above reflect capital spending requirements. for remediation to be completed in 2012.
ComEd, PECO and PECOBGE anticipate that they will fund their capital expenditures with internally generated funds and borrowings.borrowings, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 4 of the Combined Notes to Consolidated Financial Statements.
Cash Flows from Financing Activities
Cash flows provided by (used in) financing activities for the ninethree months ended September 30,March 31, 2012 and 2011 and 2010 by Registrant were as follows:
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
2011 | 2010 | 2012 | 2011 | |||||||||||||
Exelon | $ | 573 | $ | (1,350 | ) | $ | (649 | ) | $ | 261 | ||||||
Generation | (14 | ) | 48 | (601 | ) | (38 | ) | |||||||||
ComEd | 967 | (29 | ) | (226 | ) | 572 | ||||||||||
PECO | (258 | ) | (851 | ) | (88 | ) | (117 | ) | ||||||||
BGE | (4 | ) | (91 | ) |
Debt
See Note 78 of the Combined Notes to the Consolidated Financial Statements for further details of the Registrants’ debt issuances and retirements.
Dividends
Cash dividend payments and distributions during the ninethree months ended September 30,March 31, 2012 and 2011 and 2010 by Registrant were as follows:
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
2011 | 2010 | 2012 | 2011 | |||||||||||||
Exelon | $ | 1,044 | $ | 1,042 | $ | 350 | $ | 348 | ||||||||
Generation | 61 | 623 | 600 | — | ||||||||||||
ComEd | 225 | 225 | 75 | 75 | ||||||||||||
PECO | 271 | 181 | 88 | 112 | ||||||||||||
BGE | 3 | 88 | (a) |
(a) | Dividends on common stock for $85 million were paid to Constellation for the three months ended March 31, 2011. |
Second Quarter 2012 Dividend
On January 24, 2012, the Exelon Board of Directors declared a second quarter 2012 regular quarterly dividend of $0.525 per share on Exelon’s common stock contingent on the merger with Constellation. Based on the effective date of the merger, shareholders will receive two separate dividend payments totaling $0.525 per share as follows:
The first of the dividend payments was pro-rated, with shareholders of record as of the end of day before the effective date of the merger (March 12, 2012) receiving $0.00583 per share per day for the period from and including February 16, 2012, the day after the record date for the previous dividend, through and including the day before the effective date of the merger. This portion of the dividend, totaling $97 million, was paid on April 10, 2012.
The second of the dividend payments will also be pro-rated, with all Exelon shareholders, including the former Constellation shareholders, of record at the end of the day on May 15, 2012, receiving $0.00583 per share per day for the period from and including the effective date of the merger (March 12, 2012) through and including May 15, 2012. This portion of the dividend, totaling approximately $323 million, will be paid on June 8, 2012.
Short-Term Borrowings
During the ninethree months ended September 30, 2011,March 31, 2012, Exelon repaid $161 million of outstanding commercial paper and Exelon GenerationComEd issued $389 million and $73$302 million of commercial paper, respectively.paper. During the ninethree months ended September 30, 2010,March 31, 2011, ComEd repaid $155 million of outstanding borrowings under its credit agreement and issued $65$50 million of commercial paper.
Contributions from Parent/Member
ContributionsDuring the three months ended March 31, 2012 and 2011, there were no contributions from Parent/Member (Exelon) during the nine months ended September 30, 2011 and 2010 by Registrant were as follows:.
Nine Months Ended September 30, | ||||||||
2011 | 2010 | |||||||
Generation | $ | 30 | $ | 3 | ||||
ComEd | — | 2 | ||||||
PECO(a) | 18 | 136 |
|
Other
For the ninethree months ended September 30, 2011,March 31, 2012, other financing activities primarily consistconsists of expenses paid related to the replacement of the Registrants’ credit facilities. See Note 78 of the Combined Notes to Consolidated Financial Statements for additional information.
Credit Matters
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 $7.7$11.4 billion in aggregate total commitments of which $6.9$8.5 billion was available as of September 30, 2011,March 31, 2012, and of which no financial institution has more than 9%13% of the aggregate commitments. Exelon, Generation, ComEd, PECO and PECOBGE had access to the commercial paper market during the thirdfirst quarter of 2011.2012 to fund their short-term liquidity needs, when necessary. 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 Factors1A. RISK FACTORS of Exelon’s 20102011 Annual Report on Form 10-K for further information regarding the effects of uncertainty in the capital and credit markets or significant bank failures.
The Registrants believe their cash flow from operations,operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of September 30, 2011,March 31, 2012, it would have been required to provide incremental collateral of $1,155 million,$2.8 billion, which is well within its current available credit facility capacities of $5.4 billion. The $1,155 million$4.2 billion, which includes $948 million of collateral obligations for 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 $207 million of financial assurances that Generation would be required to provide Nuclear Electric Insurance Limited related to annual retrospective premium obligations.agreements. If ComEd lost its investment grade credit rating as of September 30, 2011,March 31, 2012, it would have been required to provide incremental collateral of $214$218 million, which is well within its current available credit facility capacity of $804$697 million, which takes into account commercial paper borrowings as of September 30, 2011.March 31, 2012. If PECO lost its investment grade credit rating as of September 30, 2011,March 31, 2012, it would have been required to provide collateral of $7$1 million pursuant to PJM’s credit policy and could have been required to provide collateral of $44$48 million related to its natural gas procurement contracts, which, in the aggregate, is well within PECO’s current available credit facility capacity of $599 million. If BGE lost its investment grade credit rating as of March 31, 2012, it would have been required to provide collateral of $3 million pursuant to PJM’s credit policy. Both this collateral as well as any collateral BGE would be required to provide related to its natural gas procurement contracts are, in the aggregate, well within BGE’s current available credit facility capacity of $599 million.
Exelon Credit Facilities
Exelon, ComEd and ComEdBGE 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. 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 78 of the Combined Notes to the Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.
The following table reflects the Registrants’ commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at September 30, 2011:March 31, 2012:
Commercial Paper Programs | ||||||||||||||||||||||||
Commercial Paper Issuer | Maximum Program Size(a) | Outstanding Commercial Paper at September 30, 2011 | Average Interest Rate on Commercial Paper Borrowings for the nine months ended September 30, 2011 | Maximum Program Size(a) | Outstanding Commercial Paper at March 31, 2012 | Average Interest Rate on Commercial Paper Borrowings for the three months ended March 31, 2012 | ||||||||||||||||||
Exelon Corporate | $ | 500 | $ | 389 | 0.43 | % | $ | 500 | $ | — | 0.42 | % | ||||||||||||
Generation | 5,600 | 73 | 0.47 | % | 5,600 | — | — | |||||||||||||||||
ComEd | 1,000 | — | 0.72 | % | 1,000 | 302 | 0.52 | % | ||||||||||||||||
PECO | 600 | — | — | 600 | — | — | ||||||||||||||||||
BGE | 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. |
(b) | The Exelon $1.5 billion revolver and the Exelon supplemental facilities are not currently used to support the Exelon commercial paper program. |
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have 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.
Credit Agreements | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Available Capacity at September 30, 2011 | Average Interest Rate on Facility Borrowings for nine months ended September 30, 2011 | Available Capacity at March 31, 2012 | Average Interest Rate on Facility Borrowings for three months ended March 31, 2012 | |||||||||||||||||||||||||||||||||||||||||||||||||
Borrower | Facility Type | Aggregate Bank Commitment(a) | Facility Draws | Outstanding Letters of Credit | Actual | To Support Additional Commercial Paper | 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 | $ | 103 | — | ||||||||||||||||||||||||||||||||||||||||
Exelon Corporate(b) | Syndicated Revolver | $ | 2,000 | $ | — | $ | 106 | $ | 1,894 | $ | 498 | — | ||||||||||||||||||||||||||||||||||||||||
Exelon Corporate(b) | Bilateral / Commodity Linked | 1,560 | — | 1,091 | 469 | — | — | |||||||||||||||||||||||||||||||||||||||||||||
Generation | Syndicated Revolver | 5,300 | — | 13 | 5,287 | 5,215 | — | Syndicated Revolver | 5,300 | — | 1,057 | 4,243 | 4,243 | — | ||||||||||||||||||||||||||||||||||||||
Generation | Bilateral | 300 | — | 115 | 185 | 185 | — | Bilateral | 300 | — | 299 | 1 | 1 | — | ||||||||||||||||||||||||||||||||||||||
ComEd | Syndicated Revolver | 1,000 | — | 196 | (b) | 804 | 804 | — | Syndicated Revolver | 1,000 | — | 1 | 999 | 697 | — | |||||||||||||||||||||||||||||||||||||
PECO | Syndicated Revolver | 600 | — | 1 | 599 | 599 | — | Syndicated Revolver | 600 | — | 1 | 599 | 599 | — | ||||||||||||||||||||||||||||||||||||||
BGE | Syndicated Revolver | 600 | — | 1 | 599 | 599 | — |
(a) | Excludes |
(b) |
|
Generation also has a three-year senior secured credit facility associated with certain solar projects. The amount committed under the facility is $150 million, which may be increased up to a total amount of
$200 million at the subsidiary’s request with additional commitments by the lenders. Obligations under this facility are secured by the equity interests in the subsidiary and the entities that own the solar projects as well as the assets of the subsidiary of each project entity and are guaranteed by Constellation and the project entities. As of March 31, 2012, the outstanding loan balance was $129 million.
CEU, a subsidiary of Generation, has a reserve-based lending facility that supports the upstream gas operations. The borrowing base committed under the facility is $150 million and can grow up to $500 million if the assets support a higher borrowing base and if CEU is able to obtain additional commitments from lenders. The facility expires in July 2016 and any borrowings under this facility are secured by the upstream gas properties. As of March 31, 2012, the outstanding loan balance was $35 million.
Borrowings under theeach revolving credit agreementsagreement 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 provideagreement also provides for adders of up to 85 basis points for prime-based borrowings and adders of up to 185 basis points for LIBOR-based borrowings, based upon the credit rating of the borrower. At September 30, 2011,As of March 31, 2012, the borrowings under the Exelon Generation and PECO adders were 30, 30 and 10$500 million revolving credit agreement increased to 50 basis points respectively, for prime-based borrowings and 130, 130 and 110150 basis points respectively, for LIBOR-based borrowings. Under the ComEd agreement executed on March 28, 2012, adders of up to 137.565 basis points for prime-based borrowings and 237.5165 basis points for LIBOR-based borrowings may be added based upon ComEd’s credit rating. At September 30, 2011,March 31, 2012, ComEd’s adder was 87.527.5 basis points for prime-basedprime based borrowings and 187.5127.5 basis points for LIBOR-based borrowings.
Under Generation’sthe Exelon and Generation bilateral and commodity-linked credit agreement,agreements, Exelon and Generation payspay a facility fee, payable on the first day of each calendar quarterquarterly at a rate per annum equal to a specified facility fee rate on the total amount of the credit facility regardless of usage.
Each revolving credit agreement for Exelon, Generation, ComEd and PECO 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 ninethree months ended September 30, 2011:March 31, 2012:
Exelon | Generation | ComEd | PECO | |||||||||||||
Credit agreement threshold | 2.50 to 1 | 3.00 to 1 | 2.00 to 1 | 2.00 to 1 |
At September 30, 2011,March 31, 2012, the interest coverage ratios at the Registrants were as follows:
Exelon | Generation | ComEd | PECO | |||||||||||
Interest coverage ratio | 16.13 | 29.50 | 7.18 | 8.19 |
Exelon | Generation | ComEd | PECO | |||||||||||||
Interest coverage ratio | 14.41 | 25.85 | 6.40 | 7.88 |
The BGE credit agreement contains a provision requiring BGE to maintain a Debt to Capitalization ratio equal to or less than 65%. As of March 31, 2012, the BGE Debt to Capitalization ratio as defined in its credit agreement was 46%.
An event of default under any Registrant’s credit facility will not constitute an event of default under any of the other Registrants’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or interest on any indebtedness having ain principal amount in excess of $100 million in the aggregate by Generation (including Generation’sunder its credit facility)facility will constitute an event of default under the Exelon corporate credit facility.facilities.
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 toSee Note 67 of the Combined Notes to the Consolidated Financial Statements for additional information on collateral provisions.
Intercompany Money Pool
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 ninethree months ended September 30, 2011,March 31, 2012, in addition to the net contribution or borrowing as of September 30, 2011,March 31, 2012, are presented in the following table:
Maximum Contributed | Maximum Borrowed | Contributed (Borrowed) | ||||||||||
Generation | $ | — | $ | 335 | $ | — | ||||||
PECO | 465 | — | 91 | |||||||||
BSC | — | 220 | (94 | ) | ||||||||
Exelon Corporate | 261 | N/A | 3 |
Variable-Rate Debt
See Note 7 of the Combined Notes to the Consolidated Financial Statements for discussion regarding the Registrants’ variable rate debt.
Maximum Contributed | Maximum Borrowed | Contributed (Borrowed) | ||||||||||
Generation | $ | — | $ | 78 | $ | — | ||||||
PECO | 206 | — | 117 | |||||||||
BSC | — | 136 | (117 | ) | ||||||||
Exelon Corporate | 17 | N/A | — |
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 910 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
EachAs of the Registrants hasMarch 31, 2012, Exelon, Generation, ComEd and PECO each had a current shelf registration statement effective with the SEC that provides for the sale of unspecified amounts of securities. BGE’s shelf registration was terminated in connection with the merger and ComEd’s shelf registration subsequently expired on April 30, 2012. Exelon expects to file a new single, combined shelf registration statement for all of the Registrants with the SEC in the second quarter of 2012. 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,Registrant, its securities ratings and market conditions.
Regulatory Authorizations
On February 27, 2012, ComEd received $1.3 billion in long-term debt refinancing authority from the ICC. As of September 30, 2011,March 31, 2012, ComEd had $41 million$1.4 billion available in long-term debt refinancing authority and $456 million available in new money long-term debt financing authority from the ICC, andICC. PECO had $1.9 billion available in long-term debt financing authority from the PAPUC.PAPUC and BGE had $2.0 billion available in long-term financing authority from the MDPSC.
As of September 30, 2011,March 31, 2012, ComEd and PECO had short-term financing authority from FERC, which expires on December 31, 2011,2013, of $2.5 billion and $1.5 billion, respectively. On September 16, 2011, ComEd and PECO filed applications with FERC for renewal of theirBGE had short-term financing authorities throughauthority from FERC, which expires December 31, 2013. ComEd and PECO expect resolution2012, of $0.7 billion. Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority. See Note 4 of the applications before the end of the year.Combined Notes to Consolidated Financial Statements for additional information.
Contractual Obligations and Off-Balance Sheet Arrangements
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 1315 of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants’ commitments.
Generation, ComEd, PECO and PECOBGE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd, PECO and PECOBGE 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.
Antelope Valley Project Development Agreement
On September 30, 2011, the DOE issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financingFor an in-depth discussion of the construction of the Antelope Valley solar facility. See Note 7 — Debt and Credit Agreements for additional information on the loan guaranteed by the DOE and Note 6 — Derivative Financial Instruments for additional information on the interest rate swap entered into in connection with the agreement.
General
Generation operates in three segments: Mid-Atlantic, Midwest, and 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 September 30, 2011 compared to the three months ended September 30, 2010 and the nine months ended September 30, 2011 compared to the nine months ended September 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 credit facilities of $5.6 billion that Generation currently utilizes to support its commercial paper program and to issue letters of credit.
See the “EXELON 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.
Cash Flows from Investing Activities
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’sRegistrant’s contractual obligations and off-balance sheet arrangements, is set forth under “Other Purchase Obligations” in Note 13see “Management’s Discussion and Analysis of the Combined Notes to Consolidated Financial Statements.
General
ComEd operates in a single operating segmentCondition 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 September 30, 2011 compared to the three months ended September 30, 2010, and the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010, 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, credit facility 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 September 30, 2011, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.
See “EXELON CORPORATION — Liquidity and Capital Resources” and Note 7 of the Combined Notes to the Financial Statements of this Form 10-Q for further discussion.
Capital resources are used primarily to fund ComEd’s capital requirements, including construction, retirement of debt, and contributions to Exelon’s pension plans. Additionally, ComEd operates in rate-regulated environments 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 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 13 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 PennsylvaniaArrangements” 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 thisExelon 2011 Form 10-Q.
Results of Operations
A discussion of items pertinent to PECO’s results of operations for the three months ended September 30,10-K and Constellation’s and BGE’s 2011 compared to three months ended September 30, 2010 and nine months ended September 30, 2011 compared to nine months ended September 30, 2010 is set forth under “Results of Operations — PECO” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.
Liquidity and Capital Resources
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 September 30, 2011, PECO had access to a revolving credit facility with aggregate bank commitments of $600 million.
See “EXELON 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 13 of the Combined Notes to Consolidated Financial Statements.10-K.
Item 3. | Quantitative and Qualitative Disclosures about Market Risk |
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 executive officer, chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The RMC reports to the Risk Oversight Committee of 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 RiskITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of the Registrants’ 20102011 Annual Report on Form 10-K incorporated herein by reference.
Commodity Price Risk (Exelon, Generation, ComEd, PECO and PECO)BGE)
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, contracted or contractedinvestments in generation supply in excess of Generation’s obligations to customers, including ComEd’s, PECO’s and PECO’sBGE’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, including the ComEd financial swap contract, will occur during 20112012 through 2013.2014. Generation’s energy contracts are accounted for under the accounting guidance for derivatives as further discussed in Note 67 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 September 30, 2011,March 31, 2012, the percentage of expected generation hedged was 97%-100%95%-98%, 85%-88%,68%-71% and 56%-59%40%-43% for 2011, 2012, 2013 and 2013,2014, 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 floweconomic hedges other derivatives and certain non-derivative contracts including sales to ComEd, PECO and PECOBGE 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 September 30, 2011March 31, 2012 market conditions and hedged position would be a decrease in pre-tax net income of approximately $4$63 million, $88$343 million and $349$674 million, respectively, for 2011, 2012, 2013 and 2013.2014, including coal units to be divested through September 2012. 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 profitwith the intent of benefitting from shifts or changes in market price changesprices as opposed to those entered into with the intent of hedging an exposure and isor managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary 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 1,6791,888 GWhs and 4,5081,333 GWhs for the three and nine months ended September 30,March 31, 2012 and 2011, respectively, and 1,077 GWhs and 2,885 GWhs for the three and nine months ended September 30, 2010, respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. TradingProprietary trading portfolio activity for the ninethree months ended September 30, 2011March 31, 2012 resulted in pre-tax gainslosses of $23$5 million due to net mark-to-market gains of $3 million and realized gainslosses of $20$8 million. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period, one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $110,000$51,000 of exposure over the last 18 months.months and $2 million for the last 20 days of the quarter. Because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin from continuing operations for the ninethree months ended September 30, 2011March 31, 2012 of $5,124$1,695 million, Generation has not segregated proprietary trading activity in the following tables.
Fuel Procurement.Generation procures coal and natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel assemblies are obtained primarily through long-term contracts for uranium concentrates, and long-term contracts for conversion services, enrichment services and fuel fabrication services. The supply markets for coal, natural gas, uranium concentrates and certain nuclear fuel services 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 57%55% of Generation’s uranium concentrate requirements from 20112012 through 20152016 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 impact on Exelon’s and Generation’s results of operations, cash flows and financial positions. See Note 1315 of the Combined Notes to Consolidated Financial Statements for additional information regarding uranium and coal supply agreement matters.
ComEd
The 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. The change in fair value each period is recorded by ComEd with an offset to a regulatory asset or liability. This financial swap contract between Generation and ComEd expires on May 31, 2013.
ComEd’s RFP contracts are deemed to be derivatives that qualify for the normal purchases and normal sales scope exceptionsexception under derivative accounting guidance. ComEd does not enter into derivatives for speculative or 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 6See Notes 4 and 7 of the Combined Notes to Consolidated Financial Statements.Statements for additional information regarding energy procurement and derivatives.
PECO
PECO procures electric supply for default service customers throughhas block contracts and full requirements contracts pursuant to PECO’sprocure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Program.Program, which is further discussed in Note 4 of the Combined Notes to Consolidated Financial Statements. PECO’s full requirements contracts and block contracts, thatwhich are considered derivatives, qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. Under the DSP Program, PECO is permitted to recover its electricityelectric supply procurement costs from retail customers withoutwith no mark-up.
PECO has also entered into derivative natural gas contracts, which either qualify for the normal purchases and normal sales scope exception or have no mark-to-market balances because the derivatives are index priced, to hedge its long-term price risk in the natural gas market. ThePECO’s hedging program for natural gas procurement has no direct impact on PECO’sits 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 See Note 67 of the Combined Notes to Consolidated Financial Statements.Statements for additional information on these contracts.
BGE
BGE procures electric supply for default service customers through full requirements contracts pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts that are considered derivatives qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. Under the SOS program, BGE is permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return component and an incremental cost component. However, through December 2016, BGE provides all residential electric customers a credit for the residential shareholder return component of the administrative charge.
BGE has also entered into derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its price risk in the natural gas market. The hedging program for natural gas procurement has no direct impact on BGE’s financial position. However, under BGE’s market-based rates incentive mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers.
BGE does not enter into derivatives for speculative or proprietary trading purposes. See Note 7 of the Combined Notes to Consolidated Financial Statements for additional information on these contracts.
Trading and Non-Trading Marketing ActivitiesActivities.
The following detailed presentation of Exelon’s, Generation’s, ComEd’s and PECO’sBGE’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).
The following table provides detail on changes in Exelon’s, Generation’s, ComEd’s and PECO’sBGE’s mark-to-market net asset or liability balance sheet position from December 31, 20102011 to September 30, 2011.March 31, 2012. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in accumulated OCI on the Consolidated Balance Sheets. This table excludes all normal purchase and normal sales contracts. ForRefer to Note 7 - Derivative Financial Instruments for additional information on the cash flow hedge gains and losses included within accumulated OCI and the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2011March 31, 2012 and December 31, 2010 refer to Note 6 of the Combined Notes to Consolidated Financial Statements.2011.
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 | 35 | — | — | — | 35 | |||||||||||||||
Reclassification to realized at settlement of contracts recorded in results of operations | (391 | ) | — | — | — | (391 | ) | |||||||||||||
Ineffective portion recognized in income | (4 | ) | — | — | — | (4 | ) | |||||||||||||
Reclassification to realized at settlement from accumulated OCI(b) | (617 | ) | — | — | 312 | (305 | ) | |||||||||||||
Effective portion of changes in fair value — recorded in OCI(c)(f) | (109 | ) | — | — | 4 | (105 | ) | |||||||||||||
Changes in fair value — energy derivatives(d) | — | 259 | 6 | (316 | ) | (51 | ) | |||||||||||||
Changes in collateral | 804 | — | — | — | 804 | |||||||||||||||
Changes in net option premium paid/(received) | (59 | ) | — | — | — | (59 | ) | |||||||||||||
Other income statement reclassifications(g) | (102 | ) | — | — | — | (102 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total mark-to-market energy contract net assets (liabilities) at September 30, 2011(a) | $ | 1,360 | $ | (712 | ) | $ | (3 | ) | $ | — | $ | 645 | ||||||||
|
|
|
|
|
|
|
|
|
|
Total mark-to-market energy contract net assets (liabilities) at December 31, 2011 (a) Contracts Acquired at merger date (h) Total change in fair value during 2012 of contracts recorded in result of operations Reclassification to realized at settlement of contracts recorded in results of operations Ineffective portion recognized in income (b) Reclassification to realized at settlement from accumulated OCI (c) Effective portion of changes in fair value — recorded in OCI (d) Changes in fair value — energy derivatives (e) Changes in collateral Changes in net option premium paid/(received) Other income statement reclassifications (f) Intercompany Elimination of Existing Derivative Contracts with Constellation Total mark-to-market energy contract net assets (liabilities) at March 31, 2012 (a) �� Generation ComEd BGE Intercompany
Eliminations (g) Exelon $ 1,648 $ (800 ) $ — $ — $ 848 140 140 100 — — 11 111 (32 ) — — — (32 ) (5 ) — — — (5 ) (320 ) — — 147 (173 ) 719 — — (146 ) 573 — (23 ) — (12 ) (35 ) (358 ) — — — (358 ) 100 — — — 100 (28 ) — — — (28 ) (103 ) — — — (103 ) $ 1,861 $ (823 ) $ — $ — $ 1,038
(a) | Amounts are shown net of collateral paid to and received from counterparties. |
(b) | For Generation, includes |
(c) | For Generation, includes $147 million of losses from reclassifications from accumulated OCI to recognize gains in net income related to |
For Generation, includes |
For ComEd, |
|
(f) |
|
Includes |
(g) | Amounts related to the five-year financial swap between Generation and ComEd are eliminated in consolidation. Effective prior to the merger, the five-year financial swap between Generation and ComEd was de-designated. As a result all prospective changes in fair value are recorded to operating revenue and eliminated in consolidation. |
(h) | For Generation, includes $660 million of collateral paid to counterparties. |
Fair ValuesValues.
The following tabletables 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 56 of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Exelon
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 | $ | 170 | $ | 92 | $ | 21 | $ | (25 | ) | $ | — | $ | — | $ | 258 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total | $ | 170 | $ | 92 | $ | 21 | $ | (25 | ) | $ | — | $ | — | $ | 258 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Normal Operations, other derivative contracts(b)(c): | ||||||||||||||||||||||||||||
Actively quoted prices | $ | — | $ | (1 | ) | $ | — | $ | — | $ | — | $ | — | $ | (1 | ) | ||||||||||||
Prices provided by external sources | 128 | 118 | 106 | 58 | 3 | — | 413 | |||||||||||||||||||||
Prices based on model or other valuation methods(d) | 10 | 17 | (14 | ) | (13 | ) | (7 | ) | (18 | ) | (25 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total | $ | 138 | $ | 134 | $ | 92 | $ | 45 | $ | (4 | ) | $ | (18 | ) | $ | 387 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturities Within | ||||||||||||||||||||||||||||
2012 | 2013 | 2014 | 2015 | 2016 | 2017 and Beyond | Total Fair Value | ||||||||||||||||||||||
Normal Operations, economic hedge contracts (a)(b): | ||||||||||||||||||||||||||||
Actively quoted prices (Level 1) | $ | (76 | ) | $ | (27 | ) | $ | (110 | ) | $ | (31 | ) | $ | 12 | $ | 3 | $ | (229 | ) | |||||||||
Prices provided by external sources (Level 2) | 172 | 316 | 308 | 101 | 13 | (2 | ) | 908 | ||||||||||||||||||||
Prices based on model or other valuation methods (Level 3) (c) | 181 | 104 | 59 | 41 | 23 | (49 | ) | 359 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total | $ | 277 | $ | 393 | $ | 257 | $ | 111 | $ | 48 | $ | (48 | ) | $ | 1,038 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts |
Amounts are shown net of collateral paid to and received from counterparties of |
(c) | Includes ComEd’s net assets associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Generation
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 | $ | 170 | $ | 92 | $ | 21 | $ | (25 | ) | $ | — | $ | — | $ | 258 | |||||||||||||
Prices based on model or other valuation methods | 139 | 394 | 131 | — | — | — | 664 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total | $ | 309 | $ | 486 | $ | 152 | $ | (25 | ) | $ | — | $ | — | $ | 922 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Normal Operations, other derivative contracts(b)(c): | ||||||||||||||||||||||||||||
Actively quoted prices | $ | — | $ | (1 | ) | $ | — | $ | — | $ | — | $ | — | $ | (1 | ) | ||||||||||||
Prices provided by external sources | 128 | 118 | 106 | 58 | 3 | — | 413 | |||||||||||||||||||||
Prices based on model or other valuation methods | 11 | 24 | (4 | ) | (5 | ) | (1 | ) | 1 | 26 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total | $ | 139 | $ | 141 | $ | 102 | $ | 53 | $ | 2 | $ | 1 | $ | 438 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturities Within | ||||||||||||||||||||||||||||
2012 | 2013 | 2014 | 2015 | 2016 | 2017 and Beyond | Total Fair Value | ||||||||||||||||||||||
Normal Operations, economic hedge contracts(a)(b) : | ||||||||||||||||||||||||||||
Actively quoted prices (Level 1) | $ | (76 | ) | $ | (27 | ) | $ | (110 | ) | $ | (31 | ) | $ | 12 | $ | 3 | $ | (229 | ) | |||||||||
Prices provided by external sources (Level 2) | 172 | 316 | 308 | 101 | 13 | (2 | ) | 908 | ||||||||||||||||||||
Prices based on model or other valuation methods (Level 3) | 669 | 328 | 73 | 54 | 35 | 23 | 1,182 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total | $ | 765 | $ | 617 | $ | 271 | $ | 124 | $ | 60 | $ | 24 | $ | 1,861 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts |
Amounts are shown net of collateral paid to and received from counterparties of |
ComEd
Maturities Within | ||||||||||||||||||||||||||||
2011 | 2012 | 2013 | 2014 | 2015 | 2016 and beyond | Total Fair Value | ||||||||||||||||||||||
Prices based on model or other valuation methods(a) | $ | (137 | ) | $ | (401 | ) | $ | (141 | ) | $ | (8 | ) | (6 | ) | $ | (19 | ) | $ | (712 | ) |
Maturities Within | ||||||||||||||||||||||||||||
2012 | 2013 | 2014 | 2015 | 2016 | 2017 and beyond | Total Fair Value | ||||||||||||||||||||||
Prices based on model or other valuation methods (Level 3)(a) | $ | (488 | ) | $ | (223 | ) | $ | (15 | ) | $ | (13 | ) | $ | (12 | ) | $ | (72 | ) | $ | (823 | ) |
(a) | Represents ComEd’s net |
PECO
Maturities Within | Total Fair Value | |||||||||||||||||||||||||||
2011 | 2012 | 2013 | 2014 | 2015 | 2016 and Beyond | |||||||||||||||||||||||
Prices based on model or other valuation methods(a) | $ | (3 | ) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (3 | ) |
|
Credit Risk, Collateral, and Contingent Related Features (Exelon, Generation, ComEd, PECO and PECO)BGE)
The Registrants are exposed to credit-related losses in the event of non-performance by counterparties with whom they 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 67 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 September 30, 2011.March 31, 2012. 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, ICE and ICEthe Nodal commodity exchanges, which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd, PECO and PECOBGE of $57$76 million, $46 million and $38$8 million, respectively. See Note 21 of the 2010Exelon 2011 Form 10-K for further information.
Rating as of September 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 | |||||||||||||||||||||||||||||||||||
Rating as of March 31, 2012 | 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 | $ | 968 | $ | 167 | $ | 801 | 2 | $ | 192 | $ | 2,835 | $ | 895 | $ | 1,940 | — | $ | — | ||||||||||||||||||||||
Non-investment grade | 10 | 3 | 7 | — | — | 62 | 49 | 13 | — | — | ||||||||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||||||||||
Internally rated — investment grade | 35 | 7 | 28 | — | — | 617 | 19 | 598 | 1 | 293 | ||||||||||||||||||||||||||||||
Internally rated — non-investment grade | 4 | 2 | 2 | — | — | 41 | 4 | 37 | — | — | ||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||
Total | $ | 1,017 | $ | 179 | $ | 838 | 2 | $ | 192 | $ | 3,555 | $ | 967 | $ | 2,588 | 1 | $ | 293 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
Maturity of Credit Risk Exposure | Maturity of Credit Risk Exposure | |||||||||||||||||||||||||||||||
Rating as of September 30, 2011 | Less than 2 Years | 2-5 Years | Exposure Greater than 5 Years | Total Exposure Before Credit Collateral | ||||||||||||||||||||||||||||
Rating as of March 31, 2012 | Less than 2 Years | 2-5 Years | Exposure Greater than 5 Years | Total Exposure Before Credit Collateral | ||||||||||||||||||||||||||||
Investment grade | $ | 781 | $ | 136 | $ | 51 | $ | 968 | $ | 2,168 | $ | 542 | $ | 125 | $ | 2,835 | ||||||||||||||||
Non-investment grade | 10 | — | — | 10 | 35 | 27 | — | 62 | ||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||
Internally rated — investment grade | 31 | 4 | — | 35 | 391 | 189 | 37 | 617 | ||||||||||||||||||||||||
Internally rated — non-investment grade | 4 | — | — | 4 | 41 | — | — | 41 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Total | $ | 826 | $ | 140 | $ | 51 | $ | 1,017 | $ | 2,635 | $ | 758 | $ | 162 | $ | 3,555 | ||||||||||||||||
|
|
|
|
|
|
|
|
Net Credit Exposure by Type of Counterparty | As of September 30, 2011 | As of March 31, 2012 | ||||||
Financial institutions | $ | 368 | ||||||
Investor-owned utilities, marketers and power producers | 281 | $ | 1,206 | |||||
Energy cooperatives and municipalities | 152 | 798 | ||||||
Financial institutions | 488 | |||||||
Other | 37 | 96 | ||||||
|
| |||||||
Total | $ | 838 | $ | 2,588 | ||||
|
|
ComEd
There have been no significant changes or additions to ComEd’s exposures to credit risk that are described in ItemITEM 1A. Risk FactorsRISK FACTORS of Exelon’s 20102011 Annual Report on Form 10-K.
See Note 67 of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.
PECO
There have been no significant changes or additions to PECO’s exposures to credit risk as described in ItemITEM 1A. Risk FactorsRISK FACTORS of Exelon’s 20102011 Annual Report on Form 10-K.
See Note 67 of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.
BGE
There have been no significant changes or additions to BGE’s exposures to credit risk as described in ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS of BGE’s 2011 Annual Report on Form 10-K.
See Note 7 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 settledfinancial contracts for the purchase and sale of capacity, energy, fuels, RECselectricity, fossil fuel and emissions allowances.other commodities. 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, ExelonGeneration depends on access to bank credit linesfacilities, which serve as liquidity sources to fund collateral requirements.
As of September 30, 2011,March 31, 2012, Generation had $903 million cash collateral deposit payments being held by counterparties of $71 million and Generation was holding $219$1,119 million of cash collateral deposits received from
counterparties, of which $147$238 million ofin net cash collateral deposits was offset against mark-to-market assets and liabilities. As of September 30, 2011, $1March 31, 2012, $22 million of cash collateral received was not offset against net derivativesderivative positions because they wereit was not associated with energy-related derivatives. See Note 1315 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.
ComEd
As of September 30, 2011,March 31, 2012, ComEd held immaterial amounts of cash and letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts and held approximately $19 million in the form of cash and letters of credit for both annual and long-term renewable energy contracts.
PECO
As of September 30, 2011,March 31, 2012, PECO was not required to post, nor does it hold, collateral under its electricenergy supply and natural gas procurement contracts. See Note 7 of the Combined Notes to Note 6 — DerivativeConsolidated Financial InstrumentsStatements for further discussion.information.
BGE
BGE is not required to post collateral under its electric supply contracts. As of March 31, 2012, BGE was not required to post collateral under its natural gas procurement contracts, nor was it holding collateral under its electric supply and natural gas procurement contracts. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information.
RTOs and ISOs (Exelon, Generation, ComEd, PECO and PECO)BGE)
Generation, ComEd, PECO and PECOBGE 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., AESO, OIESO and the Electric Reliability Council of Texas.ERCOT. 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, ICE and ICE.the Nodal exchange. The NYMEX, ICE and ICEthe Nodal exchange clearinghouses act as the counterparty to each trade. Transactions on NYMEX, ICE and ICEthe Nodal exchange must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX, ICE and ICEthe Nodal exchange are significantly collateralized and have limited counterparty credit risk.
Long-Term Leases (Exelon)
Exelon’s consolidated balance sheets, as of September 30, 2011,March 31, 2012, included a $649$663 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases. This investment 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 $843$829 million. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms which are set at prices above the then expected fair market value of the plants at lease inception.plants. 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 arrange a service contract with a third party for a period following the lease term. In any event, Exelon is subject to residual value risk to the extent the fair value of the assets are less than the residual value. This risk is mitigated by the fair value of the fixed 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 long-term leases. Since 2008, 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.
Interest Rate Risk (Exelon, Generation, ComEd, PECO and PECO)BGE)
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.appropriate. 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 manage interest rate risks.risk. At September 30, 2011,March 31, 2012, Exelon had $100$800 million of notional amounts of fixed-to-floating interest rate swaps outstanding, of which $650 million are designated as fair value hedges and $150 million are marked to market. Generation had $516 million of notional amounts of cash flow hedges outstanding.
A Assuming the fair value and cash flow hedges are effective, a hypothetical 10%50 bps increase in the interest rates associated with variable-rate debt and interest rate swaps would result in less than a $1 million decrease in each of Exelon’s, ComEd’sGeneration’s, and PECO’s pre-tax earnings for the ninethree months ended September 30, 2011.March 31, 2012. This calculation holds all other variablevariables 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 September 30, 2011,March 31, 2012, 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 $319$394 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 ItemITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,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.
Item 4. | Controls and Procedures |
During the thirdfirst quarter of 2011,2012, each of Exelon’s, Generation’s, ComEd’s, PECO’s and PECO’sBGE’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 PECOall Registrants to ensure that (a) material information relating to 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 that 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 September 30, 2011,March 31, 2012, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO and PECOBGE concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. Exelon, Generation, ComEd and PECOAll Registrants continually strive 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 thirdfirst quarter of 20112012, other than changes resulting from the Constellation merger and BGE’s implementation of the Customer Care and Billing (CC&B) system as discussed below, that have materially affected, or are reasonably likely to materially affect, eachany of Exelon’s, Generation’s, ComEd’s, PECO’s and PECO’sBGE’s internal control over financial reporting.
On March 12, 2012, the merger between Exelon and Constellation closed. Exelon is currently in the process of integrating Constellation’s operations, processes, and internal controls. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information regarding the merger.
On January 3, 2012, BGE completed implementation of its new CC&B system that is now being utilized to bill all gas and electric customers within the BGE service territory.
Item 1. | Legal Proceedings |
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 ProceedingsLEGAL PROCEEDINGS of the Registrants’ 20102011 Form 10-K and (b) Notes 3, 4 and 1315 of the Combined Notes to Consolidated Financial Statements in PartPART I, Item 1ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
Item 1A. | Risk Factors |
Risks Related to Exelon
Exclusive of theRisks Related to the Pending Merger with Constellation described in Exelon’s 2011 Form 10-K in ITEM 1A. RISK FACTORS, Exelon is, and will continue to be, subject to the risks described in Exelon’s 2010and Constellation’s 2011 Form 10-K in (a) ITEM 1A. Risk Factors,RISK FACTORS, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and (c) ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA: Note 18 of the Combined Notes to Consolidated Financial Statements in Exelon’s 2011 Form 10-K and Supplementary Data: Note 18 — Commitments and Contingencies.12 of the Notes to Consolidated Financial Statements in Constellation’s 2011 Form 10-K. As a result of the merger agreement announced with Constellation that closed on April 28, 2011,March 12, 2012 Exelon is subject to additional risks related to the merger as described below.
Risks Related to the Proposed Merger with Constellation
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 theirthe operations of Constellation 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 ongoingExelon’s 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 companiesExelon 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’sExelon’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 towill 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.
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 or require additional concessions 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 or offer additional concessions without seeking further shareholder approval, even if such conditions and concessions 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. In addition, Exelon and Constellation recognize that government officials may seek concessions in excess of those announced by the parties and included in their regulatory filings. 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 or the offer of additional concessions 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’sExelon’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 completionExelon as a result of the proposed merger. In addition, current and prospective Exelon employees and former 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’sExelon’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 expectexpects 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 companyExelon 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 shareholdersmay encounter unexpected difficulties or costs in meeting commitments it made under various orders and agreements associated with regulatory approvals for the 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 the process to obtain regulatory approvals required for the Constellation merger, Exelon is committed to various programs, contributions, investments and market mitigation measures in several settlement agreements and regulatory approval orders. It is possible that Exelon may encounter delays unexpected difficulties or costs in meeting these reduced ownership percentages, commitments in compliance with the terms of the relevant agreements and orders. Failure to fulfill the commitments in accordance with their terms could result in increased costs or result in penalties or fines that could adversely affect Exelon’s financial position and operating results.
Item 4. Mine Safety Disclosures
Exelon, shareholders will have less voting power inGeneration, ComEd, PECO and BGE
Not applicable to 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.Registrants.
Item 6. | Exhibits |
Exhibit | Description | |
2-1 | Agreement and Plan of Merger, dated as of March 12, 2012, by and among Exelon Corporation and Constellation Energy Group, Inc. (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-2) | |
2-2 | Distribution and Assignment Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Constellation Energy Group, Inc. and RF HoldCo LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-3) | |
2-3 | Contribution and Assignment Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Exelon Energy Delivery Company, LLC and RF HoldCo LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-4) | |
2-4 | Contribution Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Exelon Ventures Company, LLC and Exelon Generation Company, LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-5) | |
4-1 | Second Supplemental Indenture, dated as of March 12, 2012, by and between Exelon Corporation, as successor to Constellation Energy Group, Inc., and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of March 24, 1999 between Constellation Energy Group, Inc. and the trustee (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-1) | |
4-2 | Second Supplemental Indenture, dated as of March 12, 2012, by and between Exelon Corporation, as successor to Constellation Energy Group, Inc., and Deutsche Bank Trust Company Americas, as trustee, supplementing the Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and the trustee (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-2) | |
4-3 | First Supplemental Indenture, dated as of March 12, 2012, by and between Exelon Corporation, as successor to Constellation Energy Group, Inc., and Deutsche Bank Trust Company Americas, as trustee, supplementing the Indenture dated as of June 19, 2008 between Constellation Energy Group, Inc. and the trustee (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-3) | |
4-4 | Amendment and Restatement Agreement, dated as of November 22, 2011, to the Credit Agreement, dated as of October 15, 2010, among Constellation Energy Group, Inc., the lenders party thereto and Bank of America, N.A., as administrative agent (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-4) | |
4-5 | Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23, 2011, among Exelon Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-5) | |
4-6 | Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23, 2011, among Exelon Generation Company, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-6) | |
4-7 | Credit Agreement dated as of March 28, 2012 among ComEd, the Lenders named therein, and JP Morgan Chase Bank, N.A. as Administrative Agent (File No. 001-01839, Form 8-K dated March 29, 2012, Exhibit 99.1) | |
10-1 | Constellation 1995 Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10(b) to Periodic Report on Form 10-Q for the quarter ended September 30, 2004 filed by Constellation Energy Group, Inc.) (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 10-1) |
Exhibit No. | Description | |
Constellation 2002 Senior Management Long-Term Incentive Plan, as | ||
Constellation Amended and Restated 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10(b) to the Current Report on Form 8-K dated June 4, 2010 filed by Constellation Energy Group, Inc.) (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 10-3) | ||
Constellation Amended and Restated Management Long-Term Incentive Plan (incorporated by reference to Exhibit 10(d) to the Periodic Report on Form 10-Q for the quarter ended September 30, 2006 filed by Constellation Energy Group, Inc.) (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 10-4) | ||
Constellation Executive Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10(b) to the Periodic Report on Form 10-Q for the quarter ended June 30, 2011 filed by Constellation Energy Group, Inc.) (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 10-5) | ||
Exelon Corporation Code of Business Conduct, as amended March 12, 2012 (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 14-1) | ||
101.INS* | XBRL | |
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 |
* |
|
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 September 30, 2011March 31, 2012 filed by the following officers for the following companies:
31-1 | — Filed by | |
31-2 | — Filed by | |
31-3 | — Filed by | |
31-4 | — Filed by | |
31-5 | — Filed by | |
31-6 | — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company | |
31-7 | — Filed by | |
31-8 | — Filed by Phillip S. Barnett for PECO Energy Company | |
31-9 | — Filed by Kenneth W. DeFontes Jr. for Baltimore Gas and Electric Company | |
31-10 | — Filed by Carim V. Khouzami for Baltimore Gas and Electric Company |
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011March 31, 2012 filed by the following officers for the following companies:
32-1 | — Filed by | |
32-2 | — Filed by | |
32-3 | — Filed by | |
32-4 | — Filed by | |
32-5 | — Filed by | |
32-6 | — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company | |
32-7 | — Filed by | |
32-8 | — Filed by Phillip S. Barnett for PECO Energy Company | |
32-9 | — Filed by Kenneth W. DeFontes Jr. for Baltimore Gas and Electric Company | |
32-10 | — Filed by Carim V. Khouzami for Baltimore Gas and Electric Company |
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.
/ | / | |
(Principal Executive Officer) |
(Principal Financial Officer) | |
/ | ||
Duane M. DesParte | ||
Vice President and Corporate Controller (Principal Accounting Officer) |
October 26, 2011May 9, 2012
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.
EXELON GENERATION COMPANY, LLC
/ | / | |
(Principal Executive Officer) | Chief Financial Officer (Principal Financial Officer) | |
/ | ||
Chief Accounting Officer | ||
(Principal Accounting Officer) |
October 26, 2011May 9, 2012
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/ |
| |
/s/ JOSEPH R. TRPIK, Jr. | ||
Anne R. Pramaggiore | Joseph R. Trpik, Jr. | |
(Principal Executive Officer) | ||
|
| |
Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | ||
/s/ KEVIN J. WADEN | ||
Kevin J. Waden | ||
Vice President and Controller (Principal Accounting Officer) |
October 26, 2011May 9, 2012
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.
/ | / | |
Phillip S. Barnett | ||
President and Chief Executive Officer (Principal Executive Officer) | Senior Vice President, (Principal Financial Officer) | |
/s/ | ||
Vice President and Controller (Principal Accounting Officer) |
October 26, 2011May 9, 2012
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.
BALTIMORE GAS AND ELECTRIC COMPANY
/S/ KENNETH W. DEFONTES Jr. | /S/ CARIM V. KHOUZAMI | |
Kenneth W. DeFontes, Jr. | Carim V. Khouzami | |
President and Chief Executive Officer (Principal Executive Officer) | Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | |
/s/ ANNE A. HAHN | ||
Anne A. Hahn | ||
Vice President and Controller (Principal Accounting Officer) |
May 9, 2012
187193