UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
July 22, 2010
Date of Report (Date of earliest event reported)
| Commission File |
Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number |
IRS
Employer | ||
| 1-16169 |
EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398 |
23-2990190 | ||
| 333-85496 |
EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959 |
23-3064219 | ||
| 1-1839 |
COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321 |
36-0938600 | ||
| 000-16844 |
PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 |
23-0970240 | ||
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Section 2 – Financial Information
| Item 2.02. | Results of Operations and Financial Condition. |
Section 7 – Regulation FD
| Item 7.01. | Regulation FD Disclosure. |
On July 22, 2010, Exelon Corporation (Exelon) announced via press release its results for the second quarter ended June 30, 2010. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the second quarter 2010 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.
Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on July 22, 2010. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 85980766. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)
Telephone replays will be available until August 5. The U.S. and Canada call-in number for replays is 800-642-1687, and the international call-in number is 706-645-9291. The conference ID number is 85980766.
Section 9 – Financial Statements and Exhibits
| Item 9.01. | Financial Statements and Exhibits. |
| (d) | Exhibits. |
| Exhibit No. |
Description | |
| 99.1 | Press release and earnings release attachments | |
| 99.2 | Earnings conference call presentation slides | |
* * * * *
This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company and PECO Energy Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
This Current Report includes 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 these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2009 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Second Quarter 2010 Quarterly Report on Form 10-Q (to be filed on July 22, 2010) in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 12; and (3) other factors discussed in filings with the Securities and Exchange Commission 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 Current 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 Current Report.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| EXELON CORPORATION EXELON GENERATION COMPANY, LLC |
| /s/ Matthew F. Hilzinger |
| Matthew F. Hilzinger |
| Senior Vice President and Chief Financial Officer |
| Exelon Corporation |
| COMMONWEALTH EDISON COMPANY |
| /s/ Joseph R. Trpik, Jr. |
| Joseph R. Trpik, Jr. |
| Senior Vice President, Chief Financial Officer and Treasurer |
| Commonwealth Edison Company |
| PECO ENERGY COMPANY |
| /s/ Phillip S. Barnett |
| Phillip S. Barnett |
| Senior Vice President and Chief Financial Officer |
| PECO Energy Company |
July 22, 2010
EXHIBIT INDEX
| Exhibit No. |
Description | |
| 99.1 | Press release and earnings release attachments | |
| 99.2 | Earnings conference call presentation slides | |
Table of Contents
EXHIBIT 99.1
| Contact: | Stacie Frank | FOR IMMEDIATE RELEASE | ||
| Investor Relations | ||||
| 312-394-3094 | ||||
| Judy Rader | ||||
| Corporate Communications | ||||
| 312-394-7417 | ||||
Exelon Announces Second Quarter Results;
Raises Guidance Range for Full Year 2010 Earnings
CHICAGO (July 22, 2010) – Exelon Corporation (NYSE: EXC) announced second quarter 2010 consolidated earnings as follows:
| Second Quarter | ||||||
| 2010 | 2009 | |||||
| Adjusted (non-GAAP) Operating Results: |
||||||
| Net Income ($ millions) |
$ | 656 | $ | 683 | ||
| Diluted Earnings per Share |
$ | 0.99 | $ | 1.03 | ||
| GAAP Results: |
||||||
| Net Income ($ millions) |
$ | 445 | $ | 657 | ||
| Diluted Earnings per Share |
$ | 0.67 | $ | 0.99 | ||
Chairman and CEO John W. Rowe said, “All three of our companies delivered sound financial and operating performance. As a result, our second quarter earnings results again exceeded our guidance range of $0.80 to $0.90 per share. Exelon Generation achieved a nuclear capacity factor of nearly 95 percent in the second quarter, and ComEd and PECO delivered strong performance amidst severe storms and record hot weather.” Because of favorable first half results, Rowe announced that Exelon has raised its 2010 earnings guidance range from $3.70 to $4.00 per share to $3.80 to $4.10 per share.
Rowe added, “Going forward, we are optimistic about Exelon’s prospects as we evaluate the coming effects of EPA regulation, act on our views of the power market recovery and pursue disciplined organic growth across our regulated and unregulated businesses.”
Second Quarter Operating Results
As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings decreased to $0.99 per share in the second quarter of 2010 from $1.03 per share in the second quarter of 2009, primarily due to:
| • | Lower energy gross margins at Exelon Generation Company, LLC (Generation) largely reflecting unfavorable market and portfolio conditions and increased nuclear fuel costs; |
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| • | Increased depreciation and amortization expense primarily related to the higher scheduled competitive transition charge (CTC) amortization expense at PECO Energy Company (PECO) and increased depreciation expense across the operating companies due to ongoing capital expenditures; and |
| • | Higher storm costs at Commonwealth Edison Company (ComEd) and PECO. |
Lower second quarter 2010 earnings were partially offset by:
| • | The effects of favorable weather conditions in the ComEd and PECO service territories; and |
| • | Decreased interest expense at PECO and Exelon Corporate related to lower outstanding debt. |
Adjusted (non-GAAP) operating earnings for the second quarter of 2010 do not include the following items (after tax) that were included in reported GAAP earnings:
| (in millions) | (per diluted share) | |||||||
| Mark-to-market losses primarily from Generation’s economic hedging activities |
$ | (75 | ) | $ | (0.11 | ) | ||
| Non-cash remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and related to CTCs received by PECO |
$ | (65 | ) | $ | (0.10 | ) | ||
| Unrealized losses related to nuclear decommissioning trust (NDT) fund investments to the extent not offset by contractual accounting |
$ | (53 | ) | $ | (0.08 | ) | ||
| Costs associated with the retirement of certain Generation fossil generating units |
$ | (12 | ) | $ | (0.02 | ) | ||
| Costs associated with the 2007 Illinois electric rate settlement agreement |
$ | (4 | ) | $ | (0.01 | ) | ||
| Costs associated with ComEd’s 2007 settlement agreement with the City of Chicago |
$ | (2 | ) | — | ||||
Adjusted (non-GAAP) operating earnings for the second quarter of 2009 did not include the following items (after tax) that were included in reported GAAP earnings:
| (in millions) | (per diluted share) | |||||||
| Mark-to-market losses primarily from Generation’s economic hedging activities |
$ | (106 | ) | $ | (0.16 | ) | ||
| Non-cash remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and a reassessment of state deferred tax rates |
$ | 66 | $ | 0.10 | ||||
| Unrealized gains related to NDT fund investments to the extent not offset by contractual accounting |
$ | 64 | $ | 0.10 | ||||
| Charge for severance costs as a result of headcount reductions as part of Exelon’s cost savings program announced in June 2009 |
$ | (24 | ) | $ | (0.04 | ) | ||
| Costs associated with the 2007 Illinois electric rate settlement agreement |
$ | (20 | ) | $ | (0.03 | ) | ||
| External costs related to Exelon’s previously proposed acquisition of NRG Energy, Inc. |
$ | (6 | ) | $ | (0.01 | ) | ||
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2010 Earnings Outlook
Exelon raised its guidance range for 2010 adjusted (non-GAAP) operating earnings from $3.70 to $4.00 per share to $3.80 to $4.10 per share. Operating earnings guidance is based on the assumption of normal weather for the balance of the year.
The outlook for 2010 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items:
| • | Mark-to-market adjustments from economic hedging activities |
| • | Unrealized gains and losses from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements |
| • | Significant impairments of assets, including goodwill |
| • | Changes in decommissioning obligation estimates |
| • | Costs associated with the 2007 Illinois electric rate settlement agreement |
| • | Costs associated with ComEd’s 2007 settlement with the City of Chicago |
| • | Costs associated with the retirement of fossil generating units |
| • | Non-cash charge resulting from the passage of Federal health care legislation |
| • | Non-cash remeasurement of income tax uncertainties |
| • | Other unusual items |
| • | Significant future changes to GAAP |
Proposed Clean Air Transport Rule
On July 6, 2010, the U.S. Environmental Protection Agency (EPA) published the proposed Clean Air Transport Rule (CATR) as the replacement to the Clean Air Interstate Rule (CAIR) that had been remanded by the U.S. Court of Appeals for the District of Columbia Circuit in 2008. The proposed CATR is one of a number of significant regulations that the EPA expects to issue that will impose more stringent requirements relating to air, water and waste controls on electric generating units. Due to its low carbon generation portfolio, Exelon will not be as significantly affected by these regulations, which would therefore result in a comparative advantage for Exelon relative to electric generators that are more reliant on fossil-fuel plants. After a period of public comments and hearings, a final CATR is expected by mid-2011. Under the proposal, the first phase of nitrogen oxide and sulfur dioxide (SO2) emissions reductions under the CATR will commence in 2012, with further reductions of SO2 emissions proposed to become effective in 2014.
Second Quarter and Recent Highlights
| • | Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,035 gigawatt-hours (GWh) in the second quarter of 2010, compared with 34,995 GWh in the second quarter of 2009. The Exelon-operated nuclear plants achieved a 94.8 percent capacity factor for the second quarter of 2010 compared with 93.9 percent for the second quarter of 2009. The Exelon-operated nuclear plants completed three scheduled refueling outages in the second quarter of 2010, the same number of scheduled refueling outages completed in the second quarter of 2009. During the second quarter of 2010, Byron Unit 2 achieved a 541-day continuous run prior to its refueling outage – a station record. The number of refueling outage days totaled 44 in the second quarter of 2010 versus 57 days in |
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| the second quarter of 2009. The number of non-refueling outage days at the Exelon-operated plants totaled 15 days in the second quarter of 2010 compared with 21 days in the second quarter of 2009. |
| • | Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet was 3.8 percent in the second quarter of 2010, compared with 3.0 percent in the second quarter of 2009. The change was largely due to higher forced outages at the Eddystone Generating Station. The equivalent availability factor for the hydroelectric facilities was 98.1 percent in the second quarter of 2010, compared with 98.8 percent in the second quarter of 2009, largely due to a major overhaul at Conowingo Generating Station in 2010. |
| • | Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of June 30, 2010 is 96 to 99 percent for 2010, 86 to 89 percent for 2011 and 57 to 60 percent for 2012. The primary objectives of Exelon’s hedging program are to manage market risks and protect the value of its generation and its investment grade balance sheet while preserving its ability to participate in improving long-term market fundamentals. |
| • | Fossil Plant Retirements Update: On May 10, 2010, PJM Interconnection, LLC (PJM) informed Exelon Power that transmission system upgrades, necessary to allow two aging fossil-fuel generating units to retire, can be completed sooner than its original analysis indicated. PJM has determined that Cromby Generating Station Unit 2 and Eddystone Generating Station Unit 2 are needed to remain in operation until December 31, 2011 and December 31, 2012, respectively, to support transmission system reliability. Previously, PJM indicated that it needed Cromby Unit 2 to remain in operation through May 31, 2012, and Eddystone Unit 2 through December 31, 2013. While it originally announced on December 2, 2009 that the units would retire for economic reasons, Exelon Power agreed to extend their operation through the timeframe defined by PJM for system reliability reasons. On June 10, 2010, Exelon filed a reliability-must-run rate schedule with the Federal Energy Regulatory Commission (FERC) to compensate for the costs of maintaining and operating the units beyond May 31, 2011, plus a reasonable return on investment. A FERC decision is expected in the fourth quarter of 2010. Also as originally announced in December 2009, two additional fossil-fuel generating units, Cromby Unit 1 and Eddystone Unit 1, will retire effective May 31, 2011. |
| • | ComEd Electric Delivery Rate Case: On June 30, 2010, ComEd filed a rate increase request with the Illinois Commerce Commission (ICC) to allow the utility to continue modernizing its electric delivery system and recover the cost of substantial investments made since the last rate filing in 2007. The requested revenue increase of $396 million would raise the average $86 residential monthly bill by approximately 7 percent or less than $6 per month. The ICC will determine any increase in rates after an 11-month proceeding with input from all stakeholders. If approved, the new rates would not take effect until June 2011. |
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| • | PECO Energy Procurement: On June 23, 2010, PECO announced the results of the third of four planned electricity purchases under its Default Service Provider program to serve residential customers that have not chosen a competitive electric generation supplier beginning January 1, 2011. At that time, the prices PECO and its customers pay for electricity will be based on competitive electric market pricing, after having been capped for more than 10 years. |
The latest purchases in May 2010 resulted in an energy price of 7.95 cents per kilowatt hour (kWh) for PECO’s residential customers. PECO’s third procurement also included electricity purchases for the small and medium customer class. When combined with 2009 purchases, the May purchases result in a price of 8.91 cents per kWh for residential customers, 8.66 cents per kWh for small commercial customers, and 8.63 cents per kWh for medium commercial customers. PECO will complete the remaining purchases in September 2010. The results of all four purchases will determine the exact price PECO’s customers will pay for electricity beginning January 1, 2011.
For the large commercial and industrial class, PECO conducted one procurement in May 2010 for full requirements fixed price products at an average winning wholesale bid price of $77.55 per kWh and will conduct one procurement in September 2010 for full requirements spot price products.
OPERATING COMPANY RESULTS
Generation consists of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations.
Second quarter 2010 net income was $382 million compared with $512 million in the second quarter of 2009. Second quarter 2010 net income included (all after tax) mark-to-market losses of $75 million from economic hedging activities before the elimination of intercompany transactions, a gain of $70 million related to the non-cash remeasurement of income tax uncertainties, unrealized losses of $53 million related to NDT fund investments, costs of $12 million associated with the retirement of certain fossil generating units and a charge of $4 million for costs associated with the 2007 Illinois electric rate settlement. Second quarter 2009 net income included (all after tax) mark-to-market losses of $106 million from economic hedging activities before the elimination of intercompany transactions, unrealized gains of $64 million related to NDT fund investments, the benefit from a reassessment of state deferred income taxes of $38 million, a charge of $18 million for the costs associated with the 2007 Illinois electric rate settlement and a charge of $9 million for the costs incurred for severance. Excluding the effects of these items, Generation’s net income in the second quarter of 2010 decreased $87 million compared with the same quarter last year primarily due to:
| • | Lower energy gross margins, largely due to unfavorable market and portfolio conditions, lower pricing from PECO under the power purchase agreement, and higher nuclear fuel costs; and |
| • | Higher operating and maintenance expense, primarily reflecting the effect of inflation. |
Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $36.87 per MWh in the second quarter of 2010 compared with $38.96 per MWh in the second quarter of 2009.
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ComEd consists of the electricity transmission and distribution operations in northern Illinois.
ComEd recorded net income of $9 million in the second quarter of 2010, compared with net income of $116 million in the second quarter of 2009. Second quarter net income in 2010 included an after-tax charge of $106 million related to the non-cash remeasurement of income tax uncertainties and after-tax costs of $2 million for the City of Chicago settlement agreement. Second quarter 2009 net income included (all after tax) the benefit from the non-cash remeasurement of income tax uncertainties of $40 million, a charge of $11 million for the costs incurred for severance, and $2 million for the costs associated with the Illinois electric rate settlement. Excluding the effects of these items, ComEd’s net income in the second quarter of 2010 was up $28 million from the same quarter last year reflecting:
| • | The effects of favorable weather conditions; |
| • | Load growth; and |
| • | Projected refunds related to Illinois electric distribution taxes. |
The increase in net income was partially offset by:
| • | Higher storm costs. |
In the second quarter of 2010, cooling degree-days in the ComEd service territory were up 76.3 percent relative to the same period in 2009 and were 39.3 percent above normal. ComEd’s total retail electric deliveries increased by 4.9 percent quarter over quarter, with gains in deliveries across all customer classes, primarily driven by the effects of favorable weather conditions.
Weather-normalized retail electric deliveries increased by 1.8 percent from the second quarter of 2009, primarily reflecting customer growth and increased average use per customer. For ComEd, weather had a favorable after-tax effect of $10 million on second quarter 2010 earnings relative to 2009 and a favorable after-tax effect of $5 million relative to normal weather that is incorporated in Exelon’s earnings guidance.
PECO consists of the electricity transmission and distribution operations and the retail natural gas distribution business in southeastern Pennsylvania.
PECO’s net income in the second quarter of 2010 was $75 million, up from $71 million in the second quarter of 2009. Second quarter 2010 net income included an after-tax interest expense charge of $22 million related to the non-cash remeasurement of income tax uncertainties. Second quarter 2009 net income included an after-tax charge of $3 million for the costs incurred for severance. Excluding the effects of these items, PECO’s net income in the second quarter of 2010 was up $23 million from the same quarter last year reflecting:
| • | Increased CTC revenue to ensure full recovery of stranded costs during 2010, the final year of the transition period, due to lower than expected sales volume in 2009, which resulted in lower energy prices under the power purchase agreement with Generation; |
| • | The effects of favorable weather conditions; and |
| • | Lower interest expense on long-term debt. |
The increase in net income was partially offset by:
| • | Higher CTC amortization, which was in accordance with PECO’s 1998 Restructuring Settlement with the PAPUC; and |
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| • | Increased storm costs. |
In the second quarter of 2010, cooling degree-days in the PECO service territory were up 66.5 percent from 2009 and were 76.5 percent above normal. Total retail electric deliveries were up 7.3 percent from last year, reflecting an increase in deliveries across all customer classes, primarily driven by the effects of favorable weather conditions. On the retail gas side, deliveries in the second quarter of 2010 were down 16.3 percent from the second quarter of 2009, largely reflecting heating degree-days that were 27.8 percent below last year and 34.7 percent below normal.
Weather-normalized retail electric deliveries decreased by 0.7 percent from the second quarter of 2009, primarily reflecting decreased residential and small commercial and industrial deliveries. For PECO, reflecting electric and gas deliveries, weather had a favorable after-tax effect of $22 million on second quarter 2010 earnings relative to 2009 and a favorable after-tax effect of $17 million relative to normal weather that is incorporated in Exelon’s earnings guidance.
Adjusted (non-GAAP) Operating Earnings
Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliations on pages 7 and 8, are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on July 22, 2010.
Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on July 22, 2010. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 85980766. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)
Telephone replays will be available until August 5. The U.S. and Canada call-in number for replays is 800-642-1687, and the international call-in number is 706-645-9291. The conference ID number is 85980766.
Forward Looking Statements
This press release includes 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 these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2009 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s
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Second Quarter 2010 Quarterly Report on Form 10-Q (to be filed on July 22, 2010) in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 12 and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.
###
Exelon Corporation is one of the nation’s largest electric utilities with more than $17 billion in annual revenues. The company has one of the industry’s largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes electricity to approximately 5.4 million customers in northern Illinois and southeastern Pennsylvania and natural gas to approximately 486,000 customers in the Philadelphia area. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.
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Table of Contents
Table of Contents
Consolidating Statements of Operations
(unaudited)
(in millions)
| Three Months Ended June 30, 2010 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated |
||||||||||||||||
| Operating revenues |
$ | 2,353 | $ | 1,499 | $ | 1,269 | $ | (723 | ) | $ | 4,398 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
549 | 771 | 535 | (721 | ) | 1,134 | ||||||||||||||
| Fuel |
350 | — | 44 | (1 | ) | 393 | ||||||||||||||
| Operating and maintenance |
691 | 276 | 150 | (3 | ) | 1,114 | ||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 21 | 13 | — | 34 | |||||||||||||||
| Depreciation and amortization |
115 | 131 | 268 | 5 | 519 | |||||||||||||||
| Taxes other than income |
61 | 44 | 77 | 4 | 186 | |||||||||||||||
| Total operating expenses |
1,766 | 1,243 | 1,087 | (716 | ) | 3,380 | ||||||||||||||
| Operating income (loss) |
587 | 256 | 182 | (7 | ) | 1,018 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense |
(37 | ) | (134 | ) | (77 | ) | (27 | ) | (275 | ) | ||||||||||
| Other, net |
(133 | ) | 8 | (1 | ) | 4 | (122 | ) | ||||||||||||
| Total other income and deductions |
(170 | ) | (126 | ) | (78 | ) | (23 | ) | (397 | ) | ||||||||||
| Income (loss) before income taxes |
417 | 130 | 104 | (30 | ) | 621 | ||||||||||||||
| Income taxes |
35 | 121 | 29 | (9 | ) | 176 | ||||||||||||||
| Net income (loss) |
$ | 382 | $ | 9 | $ | 75 | $ | (21 | ) | $ | 445 | |||||||||
| Three Months Ended June 30, 2009 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated |
||||||||||||||||
| Operating revenues |
$ | 2,378 | $ | 1,389 | $ | 1,204 | $ | (830 | ) | $ | 4,141 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
485 | 715 | 547 | (826 | ) | 921 | ||||||||||||||
| Fuel |
406 | — | 55 | (1 | ) | 460 | ||||||||||||||
| Operating and maintenance |
689 | 270 | 149 | 3 | 1,111 | |||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 14 | — | — | 14 | |||||||||||||||
| Depreciation and amortization |
72 | 124 | 230 | 13 | 439 | |||||||||||||||
| Taxes other than income |
50 | 57 | 69 | 4 | 180 | |||||||||||||||
| Total operating expenses |
1,702 | 1,180 | 1,050 | (807 | ) | 3,125 | ||||||||||||||
| Operating income (loss) |
676 | 209 | 154 | (23 | ) | 1,016 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense |
(24 | ) | (75 | ) | (49 | ) | (32 | ) | (180 | ) | ||||||||||
| Loss in equity method investments |
— | — | (6 | ) | — | (6 | ) | |||||||||||||
| Other, net |
215 | 55 | 3 | (16 | ) | 257 | ||||||||||||||
| Total other income and deductions |
191 | (20 | ) | (52 | ) | (48 | ) | 71 | ||||||||||||
| Income (loss) before income taxes |
867 | 189 | 102 | (71 | ) | 1,087 | ||||||||||||||
| Income taxes |
355 | 73 | 31 | (29 | ) | 430 | ||||||||||||||
| Net income (loss) |
$ | 512 | $ | 116 | $ | 71 | $ | (42 | ) | $ | 657 | |||||||||
| (a) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues. |
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Consolidating Statements of Operations
(unaudited)
(in millions)
| Six Months Ended June 30, 2010 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated |
||||||||||||||||
| Operating revenues |
$ | 4,773 | $ | 2,914 | $ | 2,724 | $ | (1,552 | ) | $ | 8,859 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
757 | 1,524 | 1,059 | (1,548 | ) | 1,792 | ||||||||||||||
| Fuel |
740 | — | 255 | (1 | ) | 994 | ||||||||||||||
| Operating and maintenance |
1,432 | 435 | 331 | (23 | ) | 2,175 | ||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 40 | 21 | — | 61 | |||||||||||||||
| Depreciation and amortization |
223 | 261 | 533 | 16 | 1,033 | |||||||||||||||
| Taxes other than income |
118 | 107 | 150 | 8 | 383 | |||||||||||||||
| Total operating expenses |
3,270 | 2,367 | 2,349 | (1,548 | ) | 6,438 | ||||||||||||||
| Operating income (loss) |
1,503 | 547 | 375 | (4 | ) | 2,421 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense |
(72 | ) | (218 | ) | (122 | ) | (47 | ) | (459 | ) | ||||||||||
| Other, net |
(54 | ) | 11 | 4 | 10 | (29 | ) | |||||||||||||
| Total other income and deductions |
(126 | ) | (207 | ) | (118 | ) | (37 | ) | (488 | ) | ||||||||||
| Income (loss) before income taxes |
1,377 | 340 | 257 | (41 | ) | 1,933 | ||||||||||||||
| Income taxes |
434 | 215 | 81 | 9 | 739 | |||||||||||||||
| Net income (loss) |
$ | 943 | $ | 125 | $ | 176 | $ | (50 | ) | $ | 1,194 | |||||||||
| Six Months Ended June 30, 2009 | ||||||||||||||||||||
| Generation | ComEd | PECO | Other | Exelon Consolidated |
||||||||||||||||
| Operating revenues |
$ | 4,979 | $ | 2,942 | $ | 2,718 | $ | (1,776 | ) | $ | 8,863 | |||||||||
| Operating expenses |
||||||||||||||||||||
| Purchased power |
660 | 1,598 | 1,116 | (1,770 | ) | 1,604 | ||||||||||||||
| Fuel |
915 | — | 321 | — | 1,236 | |||||||||||||||
| Operating and maintenance |
1,617 | 522 | 327 | 6 | 2,472 | |||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
— | 25 | — | — | 25 | |||||||||||||||
| Depreciation and amortization |
149 | 246 | 455 | 25 | 875 | |||||||||||||||
| Taxes other than income |
100 | 136 | 135 | 9 | 380 | |||||||||||||||
| Total operating expenses |
3,441 | 2,527 | 2,354 | (1,730 | ) | 6,592 | ||||||||||||||
| Operating income (loss) |
1,538 | 415 | 364 | (46 | ) | 2,271 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||
| Interest expense |
(52 | ) | (159 | ) | (99 | ) | (57 | ) | (367 | ) | ||||||||||
| Loss in equity method investments |
(1 | ) | — | (12 | ) | (1 | ) | (14 | ) | |||||||||||
| Other, net |
133 | 87 | 6 | (7 | ) | 219 | ||||||||||||||
| Total other income and deductions |
80 | (72 | ) | (105 | ) | (65 | ) | (162 | ) | |||||||||||
| Income (loss) before income taxes |
1,618 | 343 | 259 | (111 | ) | 2,109 | ||||||||||||||
| Income taxes |
577 | 113 | 76 | (26 | ) | 740 | ||||||||||||||
| Net income (loss) |
$ | 1,041 | $ | 230 | $ | 183 | $ | (85 | ) | $ | 1,369 | |||||||||
| (a) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues. |
2
Table of Contents
Business Segment Comparative Statements of Operations
(unaudited)
(in millions)
| Generation | ||||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
| Operating revenues |
$ | 2,353 | $ | 2,378 | $ | (25 | ) | $ | 4,773 | $ | 4,979 | $ | (206 | ) | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
549 | 485 | 64 | 757 | 660 | 97 | ||||||||||||||||||
| Fuel |
350 | 406 | (56 | ) | 740 | 915 | (175 | ) | ||||||||||||||||
| Operating and maintenance |
691 | 689 | 2 | 1,432 | 1,617 | (185 | ) | |||||||||||||||||
| Depreciation and amortization |
115 | 72 | 43 | 223 | 149 | 74 | ||||||||||||||||||
| Taxes other than income |
61 | 50 | 11 | 118 | 100 | 18 | ||||||||||||||||||
| Total operating expenses |
1,766 | 1,702 | 64 | 3,270 | 3,441 | (171 | ) | |||||||||||||||||
| Operating income |
587 | 676 | (89 | ) | 1,503 | 1,538 | (35 | ) | ||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(37 | ) | (24 | ) | (13 | ) | (72 | ) | (52 | ) | (20 | ) | ||||||||||||
| Loss in equity method investments |
— | — | — | — | (1 | ) | 1 | |||||||||||||||||
| Other, net |
(133 | ) | 215 | (348 | ) | (54 | ) | 133 | (187 | ) | ||||||||||||||
| Total other income and deductions |
(170 | ) | 191 | (361 | ) | (126 | ) | 80 | (206 | ) | ||||||||||||||
| Income before income taxes |
417 | 867 | (450 | ) | 1,377 | 1,618 | (241 | ) | ||||||||||||||||
| Income taxes |
35 | 355 | (320 | ) | 434 | 577 | (143 | ) | ||||||||||||||||
| Net income |
$ | 382 | $ | 512 | $ | (130 | ) | $ | 943 | $ | 1,041 | $ | (98 | ) | ||||||||||
| ComEd | ||||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
| Operating revenues |
$ | 1,499 | $ | 1,389 | $ | 110 | $ | 2,914 | $ | 2,942 | $ | (28 | ) | |||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
771 | 715 | 56 | 1,524 | 1,598 | (74 | ) | |||||||||||||||||
| Operating and maintenance |
276 | 270 | 6 | 435 | 522 | (87 | ) | |||||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
21 | 14 | 7 | 40 | 25 | 15 | ||||||||||||||||||
| Depreciation and amortization |
131 | 124 | 7 | 261 | 246 | 15 | ||||||||||||||||||
| Taxes other than income |
44 | 57 | (13 | ) | 107 | 136 | (29 | ) | ||||||||||||||||
| Total operating expenses |
1,243 | 1,180 | 63 | 2,367 | 2,527 | (160 | ) | |||||||||||||||||
| Operating income |
256 | 209 | 47 | 547 | 415 | 132 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(134 | ) | (75 | ) | (59 | ) | (218 | ) | (159 | ) | (59 | ) | ||||||||||||
| Other, net |
8 | 55 | (47 | ) | 11 | 87 | (76 | ) | ||||||||||||||||
| Total other income and deductions |
(126 | ) | (20 | ) | (106 | ) | (207 | ) | (72 | ) | (135 | ) | ||||||||||||
| Income before income taxes |
130 | 189 | (59 | ) | 340 | 343 | (3 | ) | ||||||||||||||||
| Income taxes |
121 | 73 | 48 | 215 | 113 | 102 | ||||||||||||||||||
| Net income |
$ | 9 | $ | 116 | $ | (107 | ) | $ | 125 | $ | 230 | $ | (105 | ) | ||||||||||
| (a) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues. |
3
Table of Contents
Business Segment Comparative Statements of Operations
(unaudited)
(in millions)
| PECO | ||||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
| Operating revenues |
$ | 1,269 | $ | 1,204 | $ | 65 | $ | 2,724 | $ | 2,718 | $ | 6 | ||||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
535 | 547 | (12 | ) | 1,059 | 1,116 | (57 | ) | ||||||||||||||||
| Fuel |
44 | 55 | (11 | ) | 255 | 321 | (66 | ) | ||||||||||||||||
| Operating and maintenance |
150 | 149 | 1 | 331 | 327 | 4 | ||||||||||||||||||
| Operating and maintenance for regulatory required programs (a) |
13 | — | 13 | 21 | — | 21 | ||||||||||||||||||
| Depreciation and amortization |
268 | 230 | 38 | 533 | 455 | 78 | ||||||||||||||||||
| Taxes other than income |
77 | 69 | 8 | 150 | 135 | 15 | ||||||||||||||||||
| Total operating expenses |
1,087 | 1,050 | 37 | 2,349 | 2,354 | (5 | ) | |||||||||||||||||
| Operating income |
182 | 154 | 28 | 375 | 364 | 11 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(77 | ) | (49 | ) | (28 | ) | (122 | ) | (99 | ) | (23 | ) | ||||||||||||
| Loss in equity method investments |
— | (6 | ) | 6 | — | (12 | ) | 12 | ||||||||||||||||
| Other, net |
(1 | ) | 3 | (4 | ) | 4 | 6 | (2 | ) | |||||||||||||||
| Total other income and deductions |
(78 | ) | (52 | ) | (26 | ) | (118 | ) | (105 | ) | (13 | ) | ||||||||||||
| Income before income taxes |
104 | 102 | 2 | 257 | 259 | (2 | ) | |||||||||||||||||
| Income taxes |
29 | 31 | (2 | ) | 81 | 76 | 5 | |||||||||||||||||
| Net income |
$ | 75 | $ | 71 | $ | 4 | $ | 176 | $ | 183 | $ | (7 | ) | |||||||||||
| (a) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues. |
| Other (b) | ||||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2010 | 2009 | Variance | 2010 | 2009 | Variance | |||||||||||||||||||
| Operating revenues |
$ | (723 | ) | $ | (830 | ) | $ | 107 | $ | (1,552 | ) | $ | (1,776 | ) | $ | 224 | ||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
(721 | ) | (826 | ) | 105 | (1,548 | ) | (1,770 | ) | 222 | ||||||||||||||
| Fuel |
(1 | ) | (1 | ) | — | (1 | ) | — | (1 | ) | ||||||||||||||
| Operating and maintenance |
(3 | ) | 3 | (6 | ) | (23 | ) | 6 | (29 | ) | ||||||||||||||
| Depreciation and amortization |
5 | 13 | (8 | ) | 16 | 25 | (9 | ) | ||||||||||||||||
| Taxes other than income |
4 | 4 | — | 8 | 9 | (1 | ) | |||||||||||||||||
| Total operating expenses |
(716 | ) | (807 | ) | 91 | (1,548 | ) | (1,730 | ) | 182 | ||||||||||||||
| Operating loss |
(7 | ) | (23 | ) | 16 | (4 | ) | (46 | ) | 42 | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(27 | ) | (32 | ) | 5 | (47 | ) | (57 | ) | 10 | ||||||||||||||
| Loss in equity method investments |
— | — | — | — | (1 | ) | 1 | |||||||||||||||||
| Other, net |
4 | (16 | ) | 20 | 10 | (7 | ) | 17 | ||||||||||||||||
| Total other income and deductions |
(23 | ) | (48 | ) | 25 | (37 | ) | (65 | ) | 28 | ||||||||||||||
| Loss before income taxes |
(30 | ) | (71 | ) | 41 | (41 | ) | (111 | ) | 70 | ||||||||||||||
| Income taxes |
(9 | ) | (29 | ) | 20 | 9 | (26 | ) | 35 | |||||||||||||||
| Net loss |
$ | (21 | ) | $ | (42 | ) | $ | 21 | $ | (50 | ) | $ | (85 | ) | $ | 35 | ||||||||
| (b) | Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities. |
4
Table of Contents
Consolidated Balance Sheets
(unaudited)
(in millions)
| June 30, 2010 |
December 31, 2009 |
|||||||
| Assets |
||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 1,168 | $ | 2,010 | ||||
| Restricted cash and investments |
33 | 40 | ||||||
| Restricted cash and cash equivalents of variable interest entity |
426 | — | ||||||
| Accounts receivable, net |
||||||||
| Customer |
1,886 | 1,563 | ||||||
| Other |
451 | 486 | ||||||
| Mark-to-market derivative assets |
418 | 376 | ||||||
| Inventories, net |
||||||||
| Fossil fuel |
174 | 198 | ||||||
| Materials and supplies |
585 | 559 | ||||||
| Other |
459 | 209 | ||||||
| Total current assets |
5,600 | 5,441 | ||||||
| Property, plant and equipment, net |
28,030 | 27,341 | ||||||
| Deferred debits and other assets |
||||||||
| Regulatory assets |
4,380 | 4,872 | ||||||
| Nuclear decommissioning trust (NDT) funds |
6,498 | 6,669 | ||||||
| Investments |
723 | 724 | ||||||
| Goodwill |
2,625 | 2,625 | ||||||
| Mark-to-market derivative assets |
627 | 649 | ||||||
| Other |
690 | 859 | ||||||
| Total deferred debits and other assets |
15,543 | 16,398 | ||||||
| Total assets |
$ | 49,173 | $ | 49,180 | ||||
| Liabilities and shareholders’ equity |
||||||||
| Current liabilities |
||||||||
| Short-term borrowings |
$ | 289 | $ | 155 | ||||
| Short-term notes payable-accounts receivable agreement |
225 | — | ||||||
| Long-term debt due within one year |
215 | 639 | ||||||
| Long-term debt of variable interest entity due within one year |
404 | — | ||||||
| Long-term debt to PECO Energy Transition Trust due within one year |
— | 415 | ||||||
| Accounts payable |
1,181 | 1,345 | ||||||
| Accrued expenses |
1,098 | 923 | ||||||
| Deferred income taxes |
114 | 152 | ||||||
| Mark-to-market derivative liabilities |
54 | 198 | ||||||
| Other |
450 | 411 | ||||||
| Total current liabilities |
4,030 | 4,238 | ||||||
| Long-term debt |
10,811 | 10,995 | ||||||
| Long-term debt to financing trusts |
390 | 390 | ||||||
| Deferred credits and other liabilities |
||||||||
| Deferred income taxes and unamortized investment tax credits |
5,474 | 5,750 | ||||||
| Asset retirement obligations |
3,527 | 3,434 | ||||||
| Pension obligations |
3,527 | 3,625 | ||||||
| Non-pension postretirement benefits obligations |
2,278 | 2,180 | ||||||
| Spent nuclear fuel obligation |
1,018 | 1,017 | ||||||
| Regulatory liabilities |
3,344 | 3,492 | ||||||
| Mark-to-market derivative liabilities |
8 | 23 | ||||||
| Other |
1,493 | 1,309 | ||||||
| Total deferred credits and other liabilities |
20,669 | 20,830 | ||||||
| Total liabilities |
35,900 | 36,453 | ||||||
| Preferred securities of subsidiary |
87 | 87 | ||||||
| Shareholders’ equity |
||||||||
| Common stock |
8,960 | 8,923 | ||||||
| Treasury stock, at cost |
(2,327 | ) | (2,328 | ) | ||||
| Retained earnings |
8,631 | 8,134 | ||||||
| Accumulated other comprehensive loss, net |
(2,078 | ) | (2,089 | ) | ||||
| Total shareholders’ equity |
13,186 | 12,640 | ||||||
| Total liabilities and shareholders’ equity |
$ | 49,173 | $ | 49,180 | ||||
5
Table of Contents
Consolidated Statements of Cash Flows
(unaudited)
(in millions)
| Six Months Ended June 30, |
||||||||
| 2010 | 2009 | |||||||
| Cash flows from operating activities |
||||||||
| Net income |
$ | 1,194 | $ | 1,369 | ||||
| Adjustments to reconcile net income to net cash flows provided by operating activities: |
||||||||
| Depreciation, amortization and accretion, including nuclear fuel amortization |
1,455 | 1,253 | ||||||
| Impairment of long-lived assets |
— | 223 | ||||||
| Deferred income taxes and amortization of investment tax credits |
(373 | ) | 149 | |||||
| Net fair value changes related to derivatives |
(123 | ) | 28 | |||||
| Net realized and unrealized (gains) losses on NDT fund investments |
59 | (43 | ) | |||||
| Other non-cash operating activities |
278 | 411 | ||||||
| Changes in assets and liabilities: |
||||||||
| Accounts receivable |
(229 | ) | 286 | |||||
| Inventories |
1 | 75 | ||||||
| Accounts payable, accrued expenses and other current liabilities |
(239 | ) | (469 | ) | ||||
| Option premiums paid, net |
(15 | ) | (39 | ) | ||||
| Counterparty collateral (posted) received, net |
(172 | ) | 246 | |||||
| Income taxes |
661 | (177 | ) | |||||
| Pension and non-pension postretirement benefit contributions |
(119 | ) | (68 | ) | ||||
| Other assets and liabilities |
(9 | ) | (197 | ) | ||||
| Net cash flows provided by operating activities |
2,369 | 3,047 | ||||||
| Cash flows from investing activities |
||||||||
| Capital expenditures |
(1,584 | ) | (1,444 | ) | ||||
| Proceeds from NDT fund sales |
12,528 | 10,150 | ||||||
| Investment in NDT funds |
(12,626 | ) | (10,279 | ) | ||||
| Change in restricted cash |
(6 | ) | 31 | |||||
| Other investing activities |
30 | (4 | ) | |||||
| Net cash flows used in investing activities |
(1,658 | ) | (1,546 | ) | ||||
| Cash flows from financing activities |
||||||||
| Changes in short-term debt |
134 | (166 | ) | |||||
| Issuance of long-term debt |
— | 485 | ||||||
| Retirement of long-term debt |
(615 | ) | (255 | ) | ||||
| Retirement of long-term debt of variable interest entity |
(402 | ) | — | |||||
| Retirement of long-term debt to financing affiliates |
— | (330 | ) | |||||
| Dividends paid on common stock |
(694 | ) | (692 | ) | ||||
| Proceeds from employee stock plans |
22 | 19 | ||||||
| Other financing activities |
2 | 5 | ||||||
| Net cash flows used in financing activities |
(1,553 | ) | (934 | ) | ||||
| Increase (decrease) in cash and cash equivalents |
(842 | ) | 567 | |||||
| Cash and cash equivalents at beginning of period |
2,010 | 1,271 | ||||||
| Cash and cash equivalents at end of period |
$ | 1,168 | $ | 1,838 | ||||
6
Table of Contents
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations
(unaudited)
(in millions, except per share data)
| Three Months Ended June 30, 2010 | Three Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 4,398 | $ | 10 | (c),(d) | $ | 4,408 | $ | 4,141 | $ | 32 | (c) | $ | 4,173 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
1,134 | (150 | )(e) | 984 | 921 | (161 | )(e) | 760 | ||||||||||||||||
| Fuel |
393 | 26 | (e) | 419 | 460 | (13 | )(e) | 447 | ||||||||||||||||
| Operating and maintenance |
1,114 | — | 1,114 | 1,111 | (54 | )(c),(i),(j) | 1,057 | |||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
34 | — | 34 | 14 | — | 14 | ||||||||||||||||||
| Depreciation and amortization |
519 | (19 | )(f) | 500 | 439 | — | 439 | |||||||||||||||||
| Taxes other than income |
186 | — | 186 | 180 | — | 180 | ||||||||||||||||||
| Total operating expenses |
3,380 | (143 | ) | 3,237 | 3,125 | (228 | ) | 2,897 | ||||||||||||||||
| Operating income |
1,018 | 153 | 1,171 | 1,016 | 260 | 1,276 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(275 | ) | 103 | (g) | (172 | ) | (180 | ) | 9 | (g) | (171 | ) | ||||||||||||
| Loss in equity method investments |
— | — | — | (6 | ) | — | (6 | ) | ||||||||||||||||
| Other, net |
(122 | ) | 159 | (g),(h) | 37 | 257 | (252 | )(g),(h) | 5 | |||||||||||||||
| Total other income and deductions |
(397 | ) | 262 | (135 | ) | 71 | (243 | ) | (172 | ) | ||||||||||||||
| Income before income taxes |
621 | 415 | 1,036 | 1,087 | 17 | 1,104 | ||||||||||||||||||
| Income taxes |
176 | 204 | (c),(d),(e),(f),(g),(h) | 380 | 430 | (9 | )(c),(e),(g),(h),(i),(j) | 421 | ||||||||||||||||
| Net income |
$ | 445 | $ | 211 | $ | 656 | $ | 657 | $ | 26 | $ | 683 | ||||||||||||
| Effective tax rate |
28.3 | % | 36.7 | % | 39.6 | % | 38.1 | % | ||||||||||||||||
| Earnings per average common share |
||||||||||||||||||||||||
| Basic |
$ | 0.67 | $ | 0.32 | $ | 0.99 | $ | 1.00 | $ | 0.04 | $ | 1.04 | ||||||||||||
| Diluted |
$ | 0.67 | $ | 0.32 | $ | 0.99 | $ | 0.99 | $ | 0.04 | $ | 1.03 | ||||||||||||
| Average common shares outstanding |
||||||||||||||||||||||||
| Basic |
661 | 661 | 659 | 659 | ||||||||||||||||||||
| Diluted |
662 | 662 | 661 | 661 | ||||||||||||||||||||
| Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP: |
||||||||||||||||||||||||
| 2007 Illinois electric rate settlement (c) |
$ | 0.01 | $ | 0.03 | ||||||||||||||||||||
| City of Chicago settlement (d) |
— | — | ||||||||||||||||||||||
| Mark-to-market impact of economic hedging activities (e) |
0.11 | 0.16 | ||||||||||||||||||||||
| Retirement of fossil generating units (f) |
0.02 | — | ||||||||||||||||||||||
| Non-cash income tax matters and state taxes (g) |
0.10 | (0.10 | ) | |||||||||||||||||||||
| Unrealized gains and losses related to NDT fund investments (h) |
0.08 | (0.10 | ) | |||||||||||||||||||||
| NRG acquisition costs (i) |
— | 0.01 | ||||||||||||||||||||||
| 2009 restructuring charges (j) |
— | 0.04 | ||||||||||||||||||||||
| Total adjustments |
$ | 0.32 | $ | 0.04 | ||||||||||||||||||||
| (a) | Results reported in accordance with accounting principles generally accepted in the United States (GAAP). |
| (b) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues. |
| (c) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (d) | Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago. |
| (e) | Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities. |
| (f) | Adjustment to exclude costs associated with the planned retirement of fossil generating units. |
| (g) | Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties and a 2009 change in state deferred income taxes. |
| (h) | Adjustment to exclude the unrealized losses in 2010 and unrealized gains in 2009 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes. |
| (i) | Adjustment to exclude external costs associated with Exelon’s proposed acquisition of NRG Energy, Inc. (NRG), which was terminated in July 2009. |
| (j) | Adjustment to exclude 2009 restructuring charges. |
7
Table of Contents
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations
(unaudited)
(in millions, except per share data)
| Six Months Ended June 30, 2010 | Six Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 8,859 | $ | 13 | (c),(d) | $ | 8,872 | $ | 8,863 | $ | 65 | (c) | $ | 8,928 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
1,792 | 35 | (e) | 1,827 | 1,604 | 40 | (e) | 1,644 | ||||||||||||||||
| Fuel |
994 | 75 | (e) | 1,069 | 1,236 | (28 | )(e) | 1,208 | ||||||||||||||||
| Operating and maintenance |
2,175 | 2 | (f) | 2,177 | 2,472 | (291 | )(c),(j),(k),(l) | 2,181 | ||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
61 | — | 61 | 25 | — | 25 | ||||||||||||||||||
| Depreciation and amortization |
1,033 | (35 | )(f) | 998 | 875 | — | 875 | |||||||||||||||||
| Taxes other than income |
383 | — | 383 | 380 | — | 380 | ||||||||||||||||||
| Total operating expenses |
6,438 | 77 | 6,515 | 6,592 | (279 | ) | 6,313 | |||||||||||||||||
| Operating income |
2,421 | (64 | ) | 2,357 | 2,271 | 344 | 2,615 | |||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(459 | ) | 103 | (g) | (356 | ) | (367 | ) | 9 | (g) | (358 | ) | ||||||||||||
| Loss in equity method investments |
— | — | — | (14 | ) | — | (14 | ) | ||||||||||||||||
| Other, net |
(29 | ) | 101 | (g),(h) | 72 | 219 | (156 | )(g),(h) | 63 | |||||||||||||||
| Total other income and deductions |
(488 | ) | 204 | (284 | ) | (162 | ) | (147 | ) | (309 | ) | |||||||||||||
| Income before income taxes |
1,933 | 140 | 2,073 | 2,109 | 197 | 2,306 | ||||||||||||||||||
| Income taxes |
739 | 15 | (c),(d),(e),(f),(g),(h),(i) | 754 | 740 | 87 | (c),(e),(g),(h),(j),(k),(l) | 827 | ||||||||||||||||
| Net income |
$ | 1,194 | $ | 125 | $ | 1,319 | $ | 1,369 | $ | 110 | $ | 1,479 | ||||||||||||
| Effective tax rate |
38.2 | % | 36.4 | % | 35.1 | % | 35.9 | % | ||||||||||||||||
| Earnings per average common share |
||||||||||||||||||||||||
| Basic |
$ | 1.81 | $ | 0.19 | $ | 2.00 | $ | 2.08 | $ | 0.17 | $ | 2.25 | ||||||||||||
| Diluted |
$ | 1.80 | $ | 0.19 | $ | 1.99 | $ | 2.07 | $ | 0.17 | $ | 2.24 | ||||||||||||
| Average common shares outstanding |
||||||||||||||||||||||||
| Basic |
661 | 661 | 659 | 659 | ||||||||||||||||||||
| Diluted |
662 | 662 | 661 | 661 | ||||||||||||||||||||
| Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP: |
||||||||||||||||||||||||
| 2007 Illinois electric rate settlement (c) |
$ | 0.01 | $ | 0.06 | ||||||||||||||||||||
| City of Chicago settlement (d) |
— | — | ||||||||||||||||||||||
| Mark-to-market impact of economic hedging activities (e) |
(0.10 | ) | (0.01 | ) | ||||||||||||||||||||
| Retirement of fossil generating units (f) |
0.03 | — | ||||||||||||||||||||||
| Non-cash income tax matters and state taxes (g) |
0.10 | (0.10 | ) | |||||||||||||||||||||
| Unrealized gains and losses related to NDT fund investments (h) |
0.05 | (0.05 | ) | |||||||||||||||||||||
| Non-cash charge resulting from health care legislation (i) |
0.10 | — | ||||||||||||||||||||||
| NRG acquisition costs (j) |
— | 0.03 | ||||||||||||||||||||||
| Impairment of certain generating assets (k) |
— | 0.20 | ||||||||||||||||||||||
| 2009 restructuring charges (l) |
— | 0.04 | ||||||||||||||||||||||
| Total adjustments |
$ | 0.19 | $ | 0.17 | ||||||||||||||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues. |
| (c) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (d) | Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago. |
| (e) | Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities. |
| (f) | Adjustment to exclude costs associated with the planned retirement of fossil generating units. |
| (g) | Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties and a 2009 change in state deferred income taxes. |
| (h) | Adjustment to exclude the unrealized losses in 2010 and unrealized gains in 2009 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes. |
| (i) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
| (j) | Adjustment to exclude external costs associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (k) | Adjustment to exclude the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009. |
| (l) | Adjustment to exclude 2009 restructuring charges. |
8
Table of Contents
Reconciliation of Adjusted (non-GAAP) Operating
Earnings to GAAP Earnings (in millions)
Three Months Ended June 30, 2010 and 2009
| Exelon Earnings per Diluted Share |
Generation | ComEd | PECO | Other | Exelon | |||||||||||||||||||
| 2009 GAAP Earnings (Loss) |
$ | 0.99 | $ | 512 | $ | 116 | $ | 71 | $ | (42 | ) | $ | 657 | |||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
0.03 | 18 | 2 | — | — | 20 | ||||||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
0.16 | 106 | — | — | — | 106 | ||||||||||||||||||
| Unrealized Gains Related to NDT Fund Investments (1) |
(0.10 | ) | (64 | ) | — | — | — | (64 | ) | |||||||||||||||
| NRG Acquisition Costs (2) |
0.01 | — | — | — | 6 | 6 | ||||||||||||||||||
| 2009 Restructuring Charges (3) |
0.04 | 9 | 11 | 3 | 1 | 24 | ||||||||||||||||||
| Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (4) |
(0.10 | ) | (38 | ) | (40 | ) | — | 12 | (66 | ) | ||||||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) |
1.03 | 543 | 89 | 74 | (23 | ) | 683 | |||||||||||||||||
| Year Over Year Effects on Earnings: |
||||||||||||||||||||||||
| Generation Energy Margins, Excluding Mark-to-Market: |
||||||||||||||||||||||||
| Nuclear Output (5) |
(0.01 | ) | (5 | ) | — | — | — | (5 | ) | |||||||||||||||
| Nuclear Fuel Costs (6) |
(0.03 | ) | (18 | ) | — | — | — | (18 | ) | |||||||||||||||
| Market and Portfolio Conditions (7) |
(0.01 | ) | (9 | ) | — | — | — | (9 | ) | |||||||||||||||
| ComEd and PECO Margins: |
||||||||||||||||||||||||
| Weather |
0.05 | — | 10 | 22 | — | 32 | ||||||||||||||||||
| Load (8) |
— | — | 3 | (1 | ) | — | 2 | |||||||||||||||||
| Other Energy Delivery |
— | — | 4 | (7 | ) | — | (3 | ) | ||||||||||||||||
| Competitive Transition Charge (CTC) Recoveries (9) |
— | (35 | ) | — | 37 | (2 | ) | — | ||||||||||||||||
| Operating and Maintenance Expense: |
||||||||||||||||||||||||
| Bad Debt (10) |
0.01 | 1 | 1 | 5 | — | 7 | ||||||||||||||||||
| Labor, Contracting and Materials (11) |
(0.02 | ) | (12 | ) | 2 | (2 | ) | — | (12 | ) | ||||||||||||||
| Planned Nuclear Refueling Outages (12) |
0.01 | 4 | — | — | — | 4 | ||||||||||||||||||
| Other Operating and Maintenance (13) |
(0.03 | ) | — | (8 | ) | (7 | ) | (6 | ) | (21 | ) | |||||||||||||
| Pension and Non-Pension Postretirement Benefits (14) |
— | (3 | ) | — | — | — | (3 | ) | ||||||||||||||||
| Depreciation and Amortization Expense (15) |
(0.02 | ) | (15 | ) | (3 | ) | (1 | ) | 7 | (12 | ) | |||||||||||||
| Scheduled CTC Amortization Expense (16) |
(0.04 | ) | — | — | (25 | ) | — | (25 | ) | |||||||||||||||
| Income Taxes (17) |
0.02 | 14 | (1 | ) | (1 | ) | 2 | 14 | ||||||||||||||||
| Interest Expense (18) |
0.02 | (9 | ) | 5 | 10 | 6 | 12 | |||||||||||||||||
| Other (19) |
0.01 | — | 15 | (7 | ) | 2 | 10 | |||||||||||||||||
| 2010 Adjusted (non-GAAP) Operating Earnings (Loss) |
0.99 | 456 | 117 | 97 | (14 | ) | 656 | |||||||||||||||||
| 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
(0.01 | ) | (4 | ) | — | — | — | (4 | ) | |||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
(0.11 | ) | (75 | ) | — | — | — | (75 | ) | |||||||||||||||
| Unrealized Losses Related to NDT Fund Investments (1) |
(0.08 | ) | (53 | ) | — | — | — | (53 | ) | |||||||||||||||
| City of Chicago Settlement with ComEd |
— | — | (2 | ) | — | — | (2 | ) | ||||||||||||||||
| Retirement of Fossil Generating Units (20) |
(0.02 | ) | (12 | ) | — | — | — | (12 | ) | |||||||||||||||
| Non-Cash Remeasurement of Income Tax Uncertainties (4) |
(0.10 | ) | 70 | (106 | ) | (22 | ) | (7 | ) | (65 | ) | |||||||||||||
| 2010 GAAP Earnings (Loss) |
$ | 0.67 | $ | 382 | $ | 9 | $ | 75 | $ | (21 | ) | $ | 445 | |||||||||||
| (1) | Reflects the impact of unrealized gains in 2009 and unrealized losses in 2010 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements. |
| (2) | Reflects external costs incurred associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (3) | Reflects severance expense associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program. |
| (4) | For 2009, reflects the impacts of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s income. For 2010, reflects the impact of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and related to CTCs received by PECO. |
| (5) | Primarily reflects the impact of increased planned nuclear outage days in the Mid-Atlantic region in 2010, including Salem. |
| (6) | Reflects the impact of higher nuclear fuel prices. |
| (7) | Reflects the impact of a decrease in realized market prices for the sale of energy, partially offset by favorable Reliability Pricing Model (RPM) capacity pricing. |
| (8) | Reflects the weather-normalized impact of increased electric deliveries of 1.8% at ComEd and decreased electric deliveries of 0.7% at PECO. |
| (9) | Reflects increased CTC revenues at PECO resulting in lower energy prices paid to Generation under the PPA, which expires December 31, 2010. Generation and PECO’s marginal tax rate differences are reflected at Exelon Corporate. |
| (10) | Primarily reflects decreased customer account charge-offs at PECO as a result of improved accounts receivable aging. |
| (11) | Primarily reflects the impact of inflation related to labor, contracting and materials expense (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 12 and 13 below), partially offset by Exelon’s ongoing cost savings program. |
| (12) | Primarily reflects the impact of decreased planned nuclear outage days in 2010, excluding Salem. |
| (13) | Primarily reflects increased storm costs in the ComEd and PECO service territories and increased nuclear refueling outage costs related to Generation’s ownership in Salem, partially offset by reduced stock-based compensation costs across the operating companies. |
| (14) | Primarily reflects the impact of a decrease in the assumed discount rate used in 2010 to calculate the pension and other postretirement benefit obligations. |
| (15) | Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impact of a first quarter 2010 depreciation study at Generation. |
| (16) | Reflects increased scheduled amortization expense of CTCs at PECO, which will be fully amortized at the end of the transition period on December 31, 2010. |
| (17) | Primarily reflects an increase in Generation’s tax benefits associated with manufacturing deduction rate increases. |
| (18) | Primarily reflects lower interest expense at PECO and Exelon Corporate due to lower outstanding debt, partially offset by increased interest expense at Generation due to higher outstanding debt. |
| (19) | Primarily reflects projected refunds related to Illinois electric distribution taxes at ComEd. |
| (20) | Primarily reflects accelerated depreciation expense associated with the planned retirement of four fossil generating units. |
9
Table of Contents
Reconciliation of Adjusted (non-GAAP) Operating
Earnings to GAAP Earnings (in millions)
Six Months Ended June 30, 2010 and 2009
| Exelon Earnings per Diluted Share |
Generation | ComEd | PECO | Other | Exelon | |||||||||||||||||||
| 2009 GAAP Earnings (Loss) |
$ | 2.07 | $ | 1,041 | $ | 230 | $ | 183 | $ | (85 | ) | $ | 1,369 | |||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
0.06 | 39 | 2 | — | — | 41 | ||||||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
(0.01 | ) | (7 | ) | — | — | — | (7 | ) | |||||||||||||||
| Unrealized Gains Related to NDT Fund Investments (1) |
(0.05 | ) | (32 | ) | — | — | — | (32 | ) | |||||||||||||||
| NRG Acquisition Costs (2) |
0.03 | — | — | — | 15 | 15 | ||||||||||||||||||
| Impairment of Certain Generating Assets (3) |
0.20 | 135 | — | — | — | 135 | ||||||||||||||||||
| 2009 Restructuring Charges (4) |
0.04 | 9 | 11 | 3 | 1 | 24 | ||||||||||||||||||
| Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (5) |
(0.10 | ) | (38 | ) | (40 | ) | — | 12 | (66 | ) | ||||||||||||||
| 2009 Adjusted (non-GAAP) Operating Earnings (Loss) |
2.24 | 1,147 | 203 | 186 | (57 | ) | 1,479 | |||||||||||||||||
| Year Over Year Effects on Earnings: |
||||||||||||||||||||||||
| Generation Energy Margins, Excluding Mark-to-Market: |
||||||||||||||||||||||||
| Nuclear Output (6) |
(0.05 | ) | (33 | ) | — | — | — | (33 | ) | |||||||||||||||
| Nuclear Fuel Costs (7) |
(0.05 | ) | (35 | ) | — | — | — | (35 | ) | |||||||||||||||
| Market and Portfolio Conditions (8) |
(0.07 | ) | (44 | ) | — | — | — | (44 | ) | |||||||||||||||
| ComEd and PECO Margins: |
||||||||||||||||||||||||
| Weather |
0.03 | — | 7 | 16 | — | 23 | ||||||||||||||||||
| Load (9) |
0.01 | — | 3 | 1 | — | 4 | ||||||||||||||||||
| Other Energy Delivery |
(0.02 | ) | — | (2 | ) | (13 | ) | — | (15 | ) | ||||||||||||||
| Competitive Transition Charge (CTC) Recoveries (10) |
— | (64 | ) | — | 70 | (6 | ) | — | ||||||||||||||||
| Operating and Maintenance Expense: |
||||||||||||||||||||||||
| Bad Debt (11) |
0.02 | (1 | ) | 3 | 12 | — | 14 | |||||||||||||||||
| Recovery of Prior Year Bad Debt Expense at ComEd (12) |
0.06 | — | 36 | — | — | 36 | ||||||||||||||||||
| Labor, Contracting and Materials (13) |
0.01 | (4 | ) | 15 | (1 | ) | — | 10 | ||||||||||||||||
| Planned Nuclear Refueling Outages (14) |
(0.04 | ) | (28 | ) | — | — | — | (28 | ) | |||||||||||||||
| Other Operating and Maintenance (15) |
(0.02 | ) | 7 | (1 | ) | (15 | ) | (5 | ) | (14 | ) | |||||||||||||
| Pension and Non-Pension Postretirement Benefits (16) |
(0.01 | ) | (9 | ) | — | — | — | (9 | ) | |||||||||||||||
| Depreciation and Amortization Expense (17) |
(0.05 | ) | (25 | ) | (8 | ) | (4 | ) | 7 | (30 | ) | |||||||||||||
| Scheduled CTC Amortization Expense (18) |
(0.08 | ) | — | — | (50 | ) | — | (50 | ) | |||||||||||||||
| Benefit From Illinois Tax Ruling (19) |
(0.06 | ) | (9 | ) | (36 | ) | — | 2 | (43 | ) | ||||||||||||||
| Income Taxes (20) |
0.02 | — | (4 | ) | (1 | ) | 21 | 16 | ||||||||||||||||
| Interest Expense (21) |
0.02 | (16 | ) | 6 | 17 | 9 | 16 | |||||||||||||||||
| Other (22) |
0.03 | 5 | 24 | (10 | ) | 3 | 22 | |||||||||||||||||
| 2010 Adjusted (non-GAAP) Operating Earnings (Loss) |
1.99 | 891 | 246 | 208 | (26 | ) | 1,319 | |||||||||||||||||
| 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments: |
||||||||||||||||||||||||
| 2007 Illinois Electric Rate Settlement |
(0.01 | ) | (6 | ) | (1 | ) | — | — | (7 | ) | ||||||||||||||
| Mark-to-Market Impact of Economic Hedging Activities |
0.10 | 67 | — | — | — | 67 | ||||||||||||||||||
| Unrealized Losses Related to NDT Fund Investments (1) |
(0.05 | ) | (33 | ) | — | — | — | (33 | ) | |||||||||||||||
| City of Chicago Settlement with ComEd |
— | — | (2 | ) | — | — | (2 | ) | ||||||||||||||||
| Retirement of Fossil Generating Units (23) |
(0.03 | ) | (20 | ) | — | — | — | (20 | ) | |||||||||||||||
| Non-Cash Charge Resulting From Health Care Legislation (24) |
(0.10 | ) | (26 | ) | (12 | ) | (10 | ) | (17 | ) | (65 | ) | ||||||||||||
| Non-Cash Remeasurement of Income Tax Uncertainties (5) |
(0.10 | ) | 70 | (106 | ) | (22 | ) | (7 | ) | (65 | ) | |||||||||||||
| 2010 GAAP Earnings (Loss) |
$ | 1.80 | $ | 943 | $ | 125 | $ | 176 | $ | (50 | ) | $ | 1,194 | |||||||||||
| (1) | Reflects the impact of unrealized gains in 2009 and unrealized losses in 2010 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements. |
| (2) | Reflects external costs incurred associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (3) | Reflects the impact of the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009. |
| (4) | Reflects severance expense associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program. |
| (5) | For 2009, reflects the impacts of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating units and a reassessment of anticipated apportionment of Exelon’s income. For 2010, reflects the impact of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and related to CTCs received by PECO. |
| (6) | Primarily reflects the impact of increased planned nuclear outage days in 2010, including Salem, partially due to steam generator replacement at Three Mile Island. |
| (7) | Reflects the impact of higher nuclear fuel prices. |
| (8) | Reflects the impact of a decrease in realized market prices for the sale of energy, partially offset by favorable RPM capacity pricing. |
| (9) | Reflects the weather-normalized impact of increased electric deliveries of 0.5% at ComEd and increased gas deliveries of 2.2% at PECO. |
| (10) | Reflects increased CTC revenues at PECO resulting in lower energy prices paid to Generation under the PPA, which expires on December 31, 2010. Generation and PECO’s marginal tax rate differences are reflected at Exelon Corporate. |
| (11) | Primarily reflects decreased customer account charge-offs at PECO as a result of improved accounts receivable aging. |
| (12) | Reflects a credit for the recovery of 2008 and 2009 bad debt expense pursuant to the Illinois Commerce Commission’s February 2010 approval of a bad debt rider, partially offset by a contribution mandated by Illinois legislation. |
| (13) | Primarily reflects the impact of Exelon’s ongoing cost savings program, partially offset by inflation related to labor, contracting and materials expense (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 14 and 15 below). |
| (14) | Primarily reflects the impact of increased planned nuclear outage days in 2010, excluding Salem, partially due to steam generator replacement at Three Mile Island. |
| (15) | Primarily reflects increased storm costs in the ComEd and PECO service territories and increased nuclear refueling outage costs related to Generation’s ownership interest in Salem, partially offset by reduced stock-based compensation costs across the operating companies and the impact of Exelon’s ongoing cost savings program. |
| (16) | Primarily reflects the impact of a decrease in the assumed discount rate used in 2010 to calculate the pension and other postretirement benefit obligations. |
| (17) | Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impact of a first quarter 2010 depreciation study at Generation. |
| (18) | Reflects increased scheduled amortization expense of CTCs at PECO, which will be fully amortized at the end of the transition period on December 31, 2010. |
| (19) | Reflects the impact of benefits associated with a February 2009 Illinois Supreme Court decision granting Illinois investment tax credits to Exelon recognized in the first quarter of 2009, which were subsequently reversed in the third quarter of 2009. |
| (20) | Primarily reflects an increase in Generation’s tax benefits associated with manufacturing deduction rate increases, partially offset by the 2009 impact of tax planning opportunities. |
| (21) | Primarily reflects lower interest expense at PECO and Exelon Corporate due to lower outstanding debt, partially offset by higher interest expense at Generation due to higher outstanding debt. |
| (22) | Primarily reflects projected refunds related to Illinois electric distribution taxes at ComEd and realized gains associated with NDT funds at Generation as a result of favorable market conditions in 2010, partially offset by increased taxes other than income at Generation and PECO. |
| (23) | Primarily reflects accelerated depreciation expense associated with the planned retirement of four fossil generating units. |
| (24) | Reflects a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
10
Table of Contents
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| Generation
|
||||||||||||||||||||||||
| Three Months Ended June 30, 2010 | Three Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 2,353 | $ | 7 | (b) | $ | 2,360 | $ | 2,378 | $ | 30 | (b) | $ | 2,408 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
549 | (150 | )(c) | 399 | 485 | (161 | )(c) | 324 | ||||||||||||||||
| Fuel |
350 | 26 | (c) | 376 | 406 | (13 | )(c) | 393 | ||||||||||||||||
| Operating and maintenance |
691 | — | 691 | 689 | (15 | )(g) | 674 | |||||||||||||||||
| Depreciation and amortization |
115 | (19 | )(d) | 96 | 72 | — | 72 | |||||||||||||||||
| Taxes other than income |
61 | — | 61 | 50 | — | 50 | ||||||||||||||||||
| Total operating expenses |
1,766 | (143 | ) | 1,623 | 1,702 | (189 | ) | 1,513 | ||||||||||||||||
| Operating income |
587 | 150 | 737 | 676 | 219 | 895 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(37 | ) | — | (37 | ) | (24 | ) | — | (24 | ) | ||||||||||||||
| Other, net |
(133 | ) | 157 | (e) | 24 | 215 | (202 | )(e),(h) | 13 | |||||||||||||||
| Total other income and deductions |
(170 | ) | 157 | (13 | ) | 191 | (202 | ) | (11 | ) | ||||||||||||||
| Income before income taxes |
417 | 307 | 724 | 867 | 17 | 884 | ||||||||||||||||||
| Income taxes |
35 | 233 | (b),(c),(d),(e),(f) | 268 | 355 | (14 | )(b),(c),(e),(g),(h) | 341 | ||||||||||||||||
| Net income |
$ | 382 | $ | 74 | $ | 456 | $ | 512 | $ | 31 | $ | 543 | ||||||||||||
| Six Months Ended June 30, 2010 | Six Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 4,773 | $ | 9 | (b) | $ | 4,782 | $ | 4,979 | $ | 63 | (b) | $ | 5,042 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
757 | 35 | (c) | 792 | 660 | 40 | (c) | 700 | ||||||||||||||||
| Fuel |
740 | 74 | (c) | 814 | 915 | (28 | )(c) | 887 | ||||||||||||||||
| Operating and maintenance |
1,432 | (2 | )(d),(i) | 1,430 | 1,617 | (238 | )(g),(j) | 1,379 | ||||||||||||||||
| Depreciation and amortization |
223 | (35 | )(d) | 188 | 149 | — | 149 | |||||||||||||||||
| Taxes other than income |
118 | — | 118 | 100 | — | 100 | ||||||||||||||||||
| Total operating expenses |
3,270 | 72 | 3,342 | 3,441 | (226 | ) | 3,215 | |||||||||||||||||
| Operating income |
1,503 | (63 | ) | 1,440 | 1,538 | 289 | 1,827 | |||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(72 | ) | — | (72 | ) | (52 | ) | — | (52 | ) | ||||||||||||||
| Loss in equity method investments |
— | — | — | (1 | ) | — | (1 | ) | ||||||||||||||||
| Other, net |
(54 | ) | 99 | (e) | 45 | 133 | (106 | )(e),(h) | 27 | |||||||||||||||
| Total other income and deductions |
(126 | ) | 99 | (27 | ) | 80 | (106 | ) | (26 | ) | ||||||||||||||
| Income before income taxes |
1,377 | 36 | 1,413 | 1,618 | 183 | 1,801 | ||||||||||||||||||
| Income taxes |
434 | 88 | (b),(c),(d),(e),(f),(i) | 522 | 577 | 77 | (b),(c),(e),(g),(h),(j) | 654 | ||||||||||||||||
| Net income |
$ | 943 | $ | (52 | ) | $ | 891 | $ | 1,041 | $ | 106 | $ | 1,147 | |||||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (c) | Adjustment to exclude the mark-to-market impact of Generation’s economic hedging activities. |
| (d) | Adjustment to exclude costs associated with the planned retirement of fossil generating units. |
| (e) | Adjustment to exclude the unrealized losses in 2010 and unrealized gains in 2009 associated with Generation’s NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements. |
| (f) | Adjustment to exclude a 2010 remeasurement of income tax uncertainties. |
| (g) | Adjustment to exclude 2009 restructuring charges. |
| (h) | Adjustment to exclude a change in state deferred income taxes. |
| (i) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
| (j) | Adjustment to exclude the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009. |
11
Table of Contents
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| ComEd
|
||||||||||||||||||||||||
| Three Months Ended June 30, 2010 | Three Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 1,499 | $ | 3 | (c) | $ | 1,502 | $ | 1,389 | $ | 2 | (e) | $ | 1,391 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
771 | — | 771 | 715 | — | 715 | ||||||||||||||||||
| Operating and maintenance |
276 | — | 276 | 270 | (20 | )(e),(f) | 250 | |||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
21 | — | 21 | 14 | — | 14 | ||||||||||||||||||
| Depreciation and amortization |
131 | — | 131 | 124 | — | 124 | ||||||||||||||||||
| Taxes other than income |
44 | — | 44 | 57 | — | 57 | ||||||||||||||||||
| Total operating expenses |
1,243 | — | 1,243 | 1,180 | (20 | ) | 1,160 | |||||||||||||||||
| Operating income |
256 | 3 | 259 | 209 | 22 | 231 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(134 | ) | 59 | (d) | (75 | ) | (75 | ) | (6 | )(d) | (81 | ) | ||||||||||||
| Other, net |
8 | — | 8 | 55 | (60 | )(d) | (5 | ) | ||||||||||||||||
| Total other income and deductions |
(126 | ) | 59 | (67 | ) | (20 | ) | (66 | ) | (86 | ) | |||||||||||||
| Income before income taxes |
130 | 62 | 192 | 189 | (44 | ) | 145 | |||||||||||||||||
| Income taxes |
121 | (46 | )(c),(d) | 75 | 73 | (17 | )(d),(e),(f) | 56 | ||||||||||||||||
| Net income |
$ | 9 | $ | 108 | $ | 117 | $ | 116 | $ | (27 | ) | $ | 89 | |||||||||||
| Six Months Ended June 30, 2010 | Six Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 2,914 | $ | 4 | (c),(e) | $ | 2,918 | $ | 2,942 | $ | 2 | (e) | $ | 2,944 | ||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
1,524 | — | 1,524 | 1,598 | — | 1,598 | ||||||||||||||||||
| Operating and maintenance |
435 | (3 | )(g) | 432 | 522 | (20 | )(e),(f) | 502 | ||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
40 | — | 40 | 25 | — | 25 | ||||||||||||||||||
| Depreciation and amortization |
261 | — | 261 | 246 | — | 246 | ||||||||||||||||||
| Taxes other than income |
107 | — | 107 | 136 | — | 136 | ||||||||||||||||||
| Total operating expenses |
2,367 | (3 | ) | 2,364 | 2,527 | (20 | ) | 2,507 | ||||||||||||||||
| Operating income |
547 | 7 | 554 | 415 | 22 | 437 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(218 | ) | 59 | (d) | (159 | ) | (159 | ) | (6 | )(d) | (165 | ) | ||||||||||||
| Other, net |
11 | — | 11 | 87 | (60 | )(d) | 27 | |||||||||||||||||
| Total other income and deductions |
(207 | ) | 59 | (148 | ) | (72 | ) | (66 | ) | (138 | ) | |||||||||||||
| Income before income taxes |
340 | 66 | 406 | 343 | (44 | ) | 299 | |||||||||||||||||
| Income taxes |
215 | (55 | )(c),(d),(e),(g) | 160 | 113 | (17 | )(d),(e),(f) | 96 | ||||||||||||||||
| Net income |
$ | 125 | $ | 121 | $ | 246 | $ | 230 | $ | (27 | ) | $ | 203 | |||||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues. |
| (c) | Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago. |
| (d) | Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties. |
| (e) | Adjustment to exclude the impact of the 2007 Illinois electric rate settlement. |
| (f) | Adjustment to exclude 2009 structuring charges. |
| (g) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
12
Table of Contents
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| PECO
|
||||||||||||||||||||||||
| Three Months Ended June 30, 2010 | Three Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 1,269 | $ | — | $ | 1,269 | $ | 1,204 | $ | — | $ | 1,204 | ||||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
535 | — | 535 | 547 | — | 547 | ||||||||||||||||||
| Fuel |
44 | — | 44 | 55 | — | 55 | ||||||||||||||||||
| Operating and maintenance |
150 | — | 150 | 149 | (5 | )(d) | 144 | |||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
13 | — | 13 | — | — | — | ||||||||||||||||||
| Depreciation and amortization |
268 | — | 268 | 230 | — | 230 | ||||||||||||||||||
| Taxes other than income |
77 | — | 77 | 69 | — | 69 | ||||||||||||||||||
| Total operating expenses |
1,087 | — | 1,087 | 1,050 | (5 | ) | 1,045 | |||||||||||||||||
| Operating income |
182 | — | 182 | 154 | 5 | 159 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(77 | ) | 36 | (c) | (41 | ) | (49 | ) | — | (49 | ) | |||||||||||||
| Loss in equity method investments |
— | — | — | (6 | ) | — | (6 | ) | ||||||||||||||||
| Other, net |
(1 | ) | 2 | (c) | 1 | 3 | — | 3 | ||||||||||||||||
| Total other income and deductions |
(78 | ) | 38 | (40 | ) | (52 | ) | — | (52 | ) | ||||||||||||||
| Income before income taxes |
104 | 38 | 142 | 102 | 5 | 107 | ||||||||||||||||||
| Income taxes |
29 | 16 | (c) | 45 | 31 | 2 | (d) | 33 | ||||||||||||||||
| Net income |
$ | 75 | $ | 22 | $ | 97 | $ | 71 | $ | 3 | $ | 74 | ||||||||||||
| Six Months Ended June 30, 2010 | Six Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | 2,724 | $ | — | $ | 2,724 | $ | 2,718 | $ | — | $ | 2,718 | ||||||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
1,059 | — | 1,059 | 1,116 | — | 1,116 | ||||||||||||||||||
| Fuel |
255 | — | 255 | 321 | — | 321 | ||||||||||||||||||
| Operating and maintenance |
331 | (2 | )(e) | 329 | 327 | (5 | )(d) | 322 | ||||||||||||||||
| Operating and maintenance for regulatory required programs (b) |
21 | — | 21 | — | — | — | ||||||||||||||||||
| Depreciation and amortization |
533 | — | 533 | 455 | — | 455 | ||||||||||||||||||
| Taxes other than income |
150 | — | 150 | 135 | — | 135 | ||||||||||||||||||
| Total operating expenses |
2,349 | (2 | ) | 2,347 | 2,354 | (5 | ) | 2,349 | ||||||||||||||||
| Operating income |
375 | 2 | 377 | 364 | 5 | 369 | ||||||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(122 | ) | 36 | (c) | (86 | ) | (99 | ) | — | (99 | ) | |||||||||||||
| Loss in equity method investments |
— | — | — | (12 | ) | — | (12 | ) | ||||||||||||||||
| Other, net |
4 | 2 | (c) | 6 | 6 | — | 6 | |||||||||||||||||
| Total other income and deductions |
(118 | ) | 38 | (80 | ) | (105 | ) | — | (105 | ) | ||||||||||||||
| Income before income taxes |
257 | 40 | 297 | 259 | 5 | 264 | ||||||||||||||||||
| Income taxes |
81 | 8 | (c),(e) | 89 | 76 | 2 | (d) | 78 | ||||||||||||||||
| Net income |
$ | 176 | $ | 32 | $ | 208 | $ | 183 | $ | 3 | $ | 186 | ||||||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues. |
| (c) | Adjustment to exclude a 2010 remeasurement of income tax uncertainties. |
| (d) | Adjustment to exclude 2009 restructuring charges. |
| (e) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
13
Table of Contents
Reconciliation of Adjusted (non-GAAP) Operating Earnings to
GAAP Consolidated Statements of Operations
(unaudited)
(in millions)
| Other
|
||||||||||||||||||||||||
| Three Months Ended June 30, 2010 | Three Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | (723 | ) | $ | — | $ | (723 | ) | $ | (830 | ) | $ | — | $ | (830 | ) | ||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
(721 | ) | — | (721 | ) | (826 | ) | — | (826 | ) | ||||||||||||||
| Fuel |
(1 | ) | — | (1 | ) | (1 | ) | — | (1 | ) | ||||||||||||||
| Operating and maintenance |
(3 | ) | — | (3 | ) | 3 | (14 | )(c),(d) | (11 | ) | ||||||||||||||
| Depreciation and amortization |
5 | — | 5 | 13 | — | 13 | ||||||||||||||||||
| Taxes other than income |
4 | — | 4 | 4 | — | 4 | ||||||||||||||||||
| Total operating expenses |
(716 | ) | — | (716 | ) | (807 | ) | (14 | ) | (821 | ) | |||||||||||||
| Operating loss |
(7 | ) | — | (7 | ) | (23 | ) | 14 | (9 | ) | ||||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(27 | ) | 8 | (b) | (19 | ) | (32 | ) | 15 | (b) | (17 | ) | ||||||||||||
| Other, net |
4 | — | 4 | (16 | ) | 10 | (b) | (6 | ) | |||||||||||||||
| Total other income and deductions |
(23 | ) | 8 | (15 | ) | (48 | ) | 25 | (23 | ) | ||||||||||||||
| Loss before income taxes |
(30 | ) | 8 | (22 | ) | (71 | ) | 39 | (32 | ) | ||||||||||||||
| Income taxes |
(9 | ) | 1 | (b) | (8 | ) | (29 | ) | 20 | (b),(c),(d) | (9 | ) | ||||||||||||
| Net loss |
$ | (21 | ) | $ | 7 | $ | (14 | ) | $ | (42 | ) | $ | 19 | $ | (23 | ) | ||||||||
| Six Months Ended June 30, 2010 | Six Months Ended June 30, 2009 | |||||||||||||||||||||||
| GAAP (a) | Adjustments | Adjusted Non-GAAP |
GAAP (a) | Adjustments | Adjusted Non-GAAP |
|||||||||||||||||||
| Operating revenues |
$ | (1,552 | ) | $ | — | $ | (1,552 | ) | $ | (1,776 | ) | $ | — | $ | (1,776 | ) | ||||||||
| Operating expenses |
||||||||||||||||||||||||
| Purchased power |
(1,548 | ) | — | (1,548 | ) | (1,770 | ) | — | (1,770 | ) | ||||||||||||||
| Fuel |
(1 | ) | — | (1 | ) | — | — | — | ||||||||||||||||
| Operating and maintenance |
(23 | ) | 8 | (e) | (15 | ) | 6 | (28 | )(c),(d) | (22 | ) | |||||||||||||
| Depreciation and amortization |
16 | — | 16 | 25 | — | 25 | ||||||||||||||||||
| Taxes other than income |
8 | — | 8 | 9 | — | 9 | ||||||||||||||||||
| Total operating expenses |
(1,548 | ) | 8 | (1,540 | ) | (1,730 | ) | (28 | ) | (1,758 | ) | |||||||||||||
| Operating loss |
(4 | ) | (8 | ) | (12 | ) | (46 | ) | 28 | (18 | ) | |||||||||||||
| Other income and deductions |
||||||||||||||||||||||||
| Interest expense |
(47 | ) | 8 | (b) | (39 | ) | (57 | ) | 15 | (b) | (42 | ) | ||||||||||||
| Loss in equity method investments |
— | — | — | (1 | ) | — | (1 | ) | ||||||||||||||||
| Other, net |
10 | — | 10 | (7 | ) | 10 | (b) | 3 | ||||||||||||||||
| Total other income and deductions |
(37 | ) | 8 | (29 | ) | (65 | ) | 25 | (40 | ) | ||||||||||||||
| Loss before income taxes |
(41 | ) | — | (41 | ) | (111 | ) | 53 | (58 | ) | ||||||||||||||
| Income taxes |
9 | (24 | )(b),(e) | (15 | ) | (26 | ) | 25 | (b),(c),(d) | (1 | ) | |||||||||||||
| Net loss |
$ | (50 | ) | $ | 24 | $ | (26 | ) | $ | (85 | ) | $ | 28 | $ | (57 | ) | ||||||||
| (a) | Results reported in accordance with GAAP. |
| (b) | Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties and a 2009 change in state deferred income taxes. |
| (c) | Adjustment to exclude external costs associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009. |
| (d) | Adjustment to exclude 2009 restructuring charges. |
| (e) | Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. |
14
Table of Contents
Exelon Generation Statistics
| Three Months Ended | ||||||||||||||||||||
| Jun. 30, 2010 | Mar. 31, 2010 | Dec. 31, 2009 | Sept. 30, 2009 | Jun. 30, 2009 | ||||||||||||||||
| Supply (in GWhs) |
||||||||||||||||||||
| Nuclear Generation |
||||||||||||||||||||
| Mid-Atlantic (a) |
11,691 | 11,776 | 11,137 | 12,349 | 12,276 | |||||||||||||||
| Midwest |
23,344 | 22,333 | 22,472 | 23,335 | 22,719 | |||||||||||||||
| Total Nuclear Generation |
35,035 | 34,109 | 33,609 | 35,684 | 34,995 | |||||||||||||||
| Fossil and Hydro Generation |
||||||||||||||||||||
| Mid-Atlantic (b) |
2,175 | 2,564 | 1,986 | 2,044 | 2,279 | |||||||||||||||
| Midwest |
7 | — | — | — | 3 | |||||||||||||||
| South |
310 | 119 | 48 | 645 | 419 | |||||||||||||||
| Total Fossil and Hydro Generation |
2,492 | 2,683 | 2,034 | 2,689 | 2,701 | |||||||||||||||
| Purchased Power |
||||||||||||||||||||
| Mid-Atlantic |
414 | 463 | 342 | 531 | 372 | |||||||||||||||
| Midwest |
1,568 | 1,914 | 1,991 | 1,923 | 1,673 | |||||||||||||||
| South |
2,695 | 2,701 | 2,851 | 4,215 | 3,231 | |||||||||||||||
| Total Purchased Power |
4,677 | 5,078 | 5,184 | 6,669 | 5,276 | |||||||||||||||
| Total Supply by Region |
||||||||||||||||||||
| Mid-Atlantic |
14,280 | 14,803 | 13,465 | 14,924 | 14,927 | |||||||||||||||
| Midwest |
24,919 | 24,247 | 24,463 | 25,258 | 24,395 | |||||||||||||||
| South |
3,005 | 2,820 | 2,899 | 4,860 | 3,650 | |||||||||||||||
| 42,204 | 41,870 | 40,827 | 45,042 | 42,972 | ||||||||||||||||
| Three Months Ended | ||||||||||||||||||||
| Jun. 30, 2010 | Mar. 31, 2010 | Dec. 31, 2009 | Sept. 30, 2009 | Jun. 30, 2009 | ||||||||||||||||
| Electric Sales (in GWhs) |
||||||||||||||||||||
| ComEd (e) |
1,895 | 3,428 | 3,439 | 3,639 | 4,215 | |||||||||||||||
| PECO |
10,044 | 10,228 | 9,588 | 10,809 | 9,277 | |||||||||||||||
| Market and Retail (e) |
30,265 | 28,214 | 27,800 | 30,594 | 29,480 | |||||||||||||||
| Total Electric Sales (c)(d) |
42,204 | 41,870 | 40,827 | 45,042 | 42,972 | |||||||||||||||
| Average Margin ($/MWh) (f) |
||||||||||||||||||||
| Mid-Atlantic |
$ | 40.83 | $ | 41.41 | $ | 43.15 | $ | 41.47 | $ | 45.76 | ||||||||||
| Midwest |
40.78 | 41.00 | 41.98 | 40.94 | 41.73 | |||||||||||||||
| South |
(14.31 | ) | (16.67 | ) | (14.49 | ) | (3.50 | ) | (6.85 | ) | ||||||||||
| Average Margin - Overall Portfolio |
$ | 36.87 | $ | 37.26 | $ | 38.36 | $ | 36.32 | $ | 38.96 | ||||||||||
| Around-the-clock Market Prices ($/MWh) (g) |
||||||||||||||||||||
| PJM West Hub |
$ | 43.21 | $ | 44.54 | $ | 37.31 | $ | 33.20 | $ | 33.70 | ||||||||||
| NiHub |
32.35 | 34.47 | 29.61 | 25.69 | 26.11 | |||||||||||||||
| Henry Hub |
4.30 | 5.15 | 4.25 | 3.15 | 3.69 | |||||||||||||||
| (a) | Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem. |
| (b) | Includes New England generation. |
| (c) | Excludes retail gas activity, trading portfolio and other operating revenue. |
| (d) | Total sales do not include trading volume of 889 GWhs, 920 GWhs, 1,599 GWhs, 1,645 GWhs and 2,003 GWhs for the three months ended June 30, 2010, March 31, 2010, December 31, 2009, September 30, 2009 and June 30, 2009, respectively. |
| (e) | ComEd line item represents sales under the 2006 ComEd Auction. Settlements of the ComEd swap and sales under the Request for Proposal (RFP) have been excluded from ComEd and included in Market and Retail sales. In addition, renewable energy credit sales to affiliates have been included within Market and Retail sales. |
| (f) | Excludes the mark-to-market impact of Generation’s economic hedging activities. |
| (g) | Represents the average for the quarter. Henry Hub prices denominated in $/mmbtu. |
15
Table of Contents
Exelon Generation Statistics
Six Months Ended June 30, 2010 and 2009
| June 30, 2010 | June 30, 2009 | |||||||
| Supply (in GWhs) |
||||||||
| Nuclear Generation |
||||||||
| Mid-Atlantic (a) |
23,467 | 24,380 | ||||||
| Midwest |
45,677 | 45,997 | ||||||
| Total Nuclear Generation |
69,144 | 70,377 | ||||||
| Fossil and Hydro Generation |
||||||||
| Mid-Atlantic (b) |
4,739 | 4,908 | ||||||
| Midwest |
7 | 4 | ||||||
| South |
429 | 554 | ||||||
| Total Fossil and Hydro Generation |
5,175 | 5,466 | ||||||
| Purchased Power |
||||||||
| Mid-Atlantic |
877 | 873 | ||||||
| Midwest |
3,482 | 3,825 | ||||||
| South |
5,396 | 6,655 | ||||||
| Total Purchased Power |
9,755 | 11,353 | ||||||
| Total Supply by Region |
||||||||
| Mid-Atlantic |
29,083 | 30,161 | ||||||
| Midwest |
49,166 | 49,826 | ||||||
| South |
5,825 | 7,209 | ||||||
| 84,074 | 87,196 | |||||||
| June 30, 2010 | June 30, 2009 | |||||||
| Electric Sales (in GWhs) |
||||||||
| ComEd (e) |
5,323 | 9,752 | ||||||
| PECO |
20,272 | 19,500 | ||||||
| Market and Retail (e) |
58,479 | 57,944 | ||||||
| Total Electric Sales (c)(d) |
84,074 | 87,196 | ||||||
| Average Margin ($/MWh) (f) |
||||||||
| Mid-Atlantic |
$ | 41.14 | $ | 45.65 | ||||
| Midwest |
40.88 | 41.95 | ||||||
| South |
(15.62 | ) | (8.04 | ) | ||||
| Average Margin - Overall Portfolio |
$ | 37.06 | $ | 39.09 | ||||
| Around-the-clock Market Prices ($/MWh) (g) |
||||||||
| PJM West Hub |
$ | 43.87 | $ | 41.40 | ||||
| NiHub |
33.40 | 30.07 | ||||||
| Henry Hub |
4.73 | 4.13 | ||||||
| (a) | Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem. |
| (b) | Includes New England generation. |
| (c) | Excludes retail gas activity, trading portfolio and other operating revenue. |
| (d) | Total sales do not include trading volume of 1,808 GWhs and 4,334 GWhs for the six months ended June 30, 2010 and 2009, respectively. |
| (e) | ComEd line item represents sales under the 2006 ComEd Auction. Settlements of the ComEd swap and sales under the RFP have been excluded from ComEd and included in Market and Retail sales. In addition, renewable energy credit sales to affiliates have been included within Market and Retail sales. |
| (f) | Excludes the mark-to-market impact of Generation’s economic hedging activities. |
| (g) | Represents the average for the six months ended June 30, 2010 and 2009, respectively. Henry Hub prices denominated in $/mmbtu. |
16
Table of Contents
ComEd Statistics
Three Months Ended June 30, 2010 and 2009
| Electric Deliveries (in GWhs) | Revenue (in millions) | |||||||||||||||||||
| 2010 | 2009 | % Change | Weather-Normal % Change |
2010 | 2009 | % Change | ||||||||||||||
| Retail Deliveries and Sales (a) |
||||||||||||||||||||
| Residential |
6,474 | 6,032 | 7.3 | % | 1.6 | % | $ | 829 | $ | 731 | 13.4 | % | ||||||||
| Small Commercial & Industrial |
7,935 | 7,739 | 2.5 | % | (0.1 | )% | 415 | 411 | 1.0 | % | ||||||||||
| Large Commercial & Industrial |
6,825 | 6,468 | 5.5 | % | 4.3 | % | 100 | 93 | 7.5 | % | ||||||||||
| Public Authorities & Electric Railroads |
277 | 275 | 0.7 | % | 1.0 | % | 16 | 14 | 14.3 | % | ||||||||||
| Total Retail |
21,511 | 20,514 | 4.9 | % | 1.8 | % | 1,360 | 1,249 | 8.9 | % | ||||||||||
| Other Revenue (b) |
139 | 140 | (0.7 | )% | ||||||||||||||||
| Total Electric Revenue |
$ | 1,499 | $ | 1,389 | 7.9 | % | ||||||||||||||
| Purchased Power |
$ | 771 | $ | 715 | 7.8 | % | ||||||||||||||
| Heating and Cooling Degree-Days | % Change | |||||||||||||||||||
| 2010 | 2009 | Normal | From 2009 | From Normal | ||||||||||||||||
| Heating Degree-Days |
519 | 768 | 766 | (32.4 | )% | (32.2 | )% | |||||||||||||
| Cooling Degree-Days |
312 | 177 | 224 | 76.3 | % | 39.3 | % | |||||||||||||
Six Months Ended June 30, 2010 and 2009
| Electric Deliveries (in GWhs) | Revenue (in millions) | |||||||||||||||||||
| 2010 | 2009 | % Change | Weather-Normal % Change |
2010 | 2009 | % Change | ||||||||||||||
| Retail Deliveries and Sales (a) |
||||||||||||||||||||
| Residential |
13,417 | 13,095 | 2.5 | % | 0.8 | % | $ | 1,606 | $ | 1,577 | 1.8 | % | ||||||||
| Small Commercial & Industrial |
15,864 | 15,889 | (0.2 | )% | (0.9 | )% | 804 | 860 | (6.5 | )% | ||||||||||
| Large Commercial & Industrial |
13,488 | 13,242 | 1.9 | % | 1.6 | % | 197 | 192 | 2.6 | % | ||||||||||
| Public Authorities & Electric Railroads |
645 | 621 | 3.9 | % | 5.5 | % | 33 | 29 | 13.8 | % | ||||||||||
| Total Retail |
43,414 | 42,847 | 1.3 | % | 0.5 | % | 2,640 | 2,658 | (0.7 | )% | ||||||||||
| Other Revenue (b) |
274 | 284 | (3.5 | )% | ||||||||||||||||
| Total Electric Revenue |
$ | 2,914 | $ | 2,942 | (1.0 | )% | ||||||||||||||
| Purchased Power |
$ | 1,524 | $ | 1,598 | (4.6 | )% | ||||||||||||||
| Heating and Cooling Degree-Days | % Change | |||||||||||||||||||
| 2010 | 2009 | Normal | From 2009 | From Normal | ||||||||||||||||
| Heating Degree-Days |
3,629 | 4,088 | 3,974 | (11.2 | )% | (8.7 | )% | |||||||||||||
| Cooling Degree-Days |
312 | 177 | 224 | 76.3 | % | 39.3 | % | |||||||||||||
| Number of Electric Customers | 2010 | 2009 | ||||||||||||||||||
| Residential |
3,432,466 | 3,423,387 | ||||||||||||||||||
| Small Commercial & Industrial |
361,326 | 358,897 | ||||||||||||||||||
| Large Commercial & Industrial |
1,982 | 2,033 | ||||||||||||||||||
| Public Authorities & Electric Railroads |
5,072 | 5,034 | ||||||||||||||||||
| Total |
3,800,846 | 3,789,351 | ||||||||||||||||||
| (a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from ComEd and customers electing to receive electric generation services from a competitive electric generation supplier. All customers are assessed charges for delivery. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy. |
| (b) | Other revenue primarily includes transmission revenue from PJM Interconnection, LLC (PJM). Other items include late payment charges and mutual assistance program revenues. |
17
Table of Contents
PECO Statistics
Three Months Ended June 30, 2010 and 2009
| Electric and Gas Deliveries | Revenue (in millions) | |||||||||||||||||||
| 2010 | 2009 | % Change | Weather- Normal % Change |
2010 | 2009 | % Change | ||||||||||||||
| Electric (in GWhs) |
||||||||||||||||||||
| Retail Deliveries and Sales (a) |
||||||||||||||||||||
| Residential |
3,118 | 2,764 | 12.8 | % | (2.3 | )% | $ | 489 | $ | 416 | 17.5 | % | ||||||||
| Small Commercial & Industrial |
2,027 | 2,013 | 0.7 | % | (5.1 | )% | 271 | 260 | 4.2 | % | ||||||||||
| Large Commercial & Industrial |
4,156 | 3,878 | 7.2 | % | 2.6 | % | 337 | 338 | (0.3 | )% | ||||||||||
| Public Authorities & Electric Railroads |
225 | 222 | 1.4 | % | 1.2 | % | 24 | 22 | 9.1 | % | ||||||||||
| Total Retail |
9,526 | 8,877 | 7.3 | % | (0.7 | )% | 1,121 | 1,036 | 8.2 | % | ||||||||||
| Other Revenue (b) |
59 | 67 | (11.9 | )% | ||||||||||||||||
| Total Electric Revenue |
1,180 | 1,103 | 7.0 | % | ||||||||||||||||
| Gas (in mmcfs) |
||||||||||||||||||||
| Retail Sales |
5,973 | 7,136 | (16.3 | )% | 1.6 | % | 81 | 95 | (14.7 | )% | ||||||||||
| Transportation and Other |
6,540 | 6,105 | 7.1 | % | (3.0 | )% | 8 | 6 | 33.3 | % | ||||||||||
| Total Gas |
12,513 | 13,241 | (5.5 | )% | (0.5 | )% | 89 | 101 | (11.9 | )% | ||||||||||
| Total Electric and Gas Revenues |
$ | 1,269 | $ | 1,204 | 5.4 | % | ||||||||||||||
| Purchased Power |
$ | 535 | $ | 547 | (2.2 | )% | ||||||||||||||
| Fuel |
44 | 55 | (20.0 | )% | ||||||||||||||||
| Total Purchased Power and Fuel |
$ | 579 | $ | 602 | (3.8 | )% | ||||||||||||||
| Heating and Cooling Degree-Days | % Change | |||||||||||||||||||
| 2010 | 2009 | Normal | From 2009 | From Normal | ||||||||||||||||
| Heating Degree-Days |
299 | 414 | 458 | (27.8 | %) | (34.7 | %) | |||||||||||||
| Cooling Degree-Days |
586 | 352 | 332 | 66.5 | % | 76.5 | % | |||||||||||||
Six Months Ended June 30, 2010 and 2009
| Electric and Gas Deliveries | Revenue (in millions) | |||||||||||||||||||
| 2010 | 2009 | % Change | Weather- Normal % Change |
2010 | 2009 | % Change | ||||||||||||||
| Electric (in GWhs) |
||||||||||||||||||||
| Retail Deliveries and Sales (a) |
||||||||||||||||||||
| Residential |
6,645 | 6,299 | 5.5 | % | (0.0 | )% | $ | 962 | $ | 882 | 9.1 | % | ||||||||
| Small Commercial & Industrial |
4,177 | 4,209 | (0.8 | )% | (2.9 | )% | 519 | 510 | 1.8 | % | ||||||||||
| Large Commercial & Industrial |
7,950 | 7,669 | 3.7 | % | 1.4 | % | 661 | 657 | 0.6 | % | ||||||||||
| Public Authorities & Electric Railroads |
471 | 469 | 0.4 | % | 0.4 | % | 47 | 45 | 4.4 | % | ||||||||||
| Total Retail |
19,243 | 18,646 | 3.2 | % | (0.1 | )% | 2,189 | 2,094 | 4.5 | % | ||||||||||
| Other Revenue (b) |
120 | 135 | (11.1 | )% | ||||||||||||||||
| Total Electric Revenue |
2,309 | 2,229 | 3.6 | % | ||||||||||||||||
| Gas (in mmcfs) |
||||||||||||||||||||
| Retail Sales |
33,557 | 35,750 | (6.1 | )% | 1.4 | % | 399 | 475 | (16.0 | )% | ||||||||||
| Transportation and Other |
15,157 | 13,983 | 8.4 | % | 4.1 | % | 16 | 14 | 14.3 | % | ||||||||||
| Total Gas |
48,714 | 49,733 | (2.0 | )% | 2.2 | % | 415 | 489 | (15.1 | )% | ||||||||||
| Total Electric and Gas Revenues |
$ | 2,724 | $ | 2,718 | 0.2 | % | ||||||||||||||
| Purchased Power |
$ | 1,059 | $ | 1,116 | (5.1 | )% | ||||||||||||||
| Fuel |
255 | 321 | (20.6 | )% | ||||||||||||||||
| Total Purchased Power and Fuel |
$ | 1,314 | $ | 1,437 | (8.6 | )% | ||||||||||||||
| Heating and Cooling Degree-Days | % Change | |||||||||||||||||||
| 2010 | 2009 | Normal | From 2009 | From Normal | ||||||||||||||||
| Heating Degree-Days |
2,710 | 2,948 | 2,968 | (8.1 | %) | (8.7 | %) | |||||||||||||
| Cooling Degree-Days |
586 | 352 | 332 | 66.5 | % | 76.5 | % | |||||||||||||
| Number of Electric Customers | 2010 | 2009 | Number of Gas Customers | 2010 | 2009 | |||||||||||||||
| Residential |
1,406,014 | 1,402,515 | Residential |
|
446,236 | 443,872 | ||||||||||||||
| Small Commercial & Industrial |
156,423 | 155,970 | Commercial & Industrial |
|
40,944 | 41,008 | ||||||||||||||
| Large Commercial & Industrial |
3,093 | 3,089 | Total Retail |
|
487,180 | 484,880 | ||||||||||||||
| Public Authorities & Electric Railroads |
1,081 | 1,085 | Transportation |
|
805 | 755 | ||||||||||||||
| Total |
1,566,611 | 1,562,659 | Total | 487,985 | 485,635 | |||||||||||||||
| (a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers electing to receive electric generation service from a competitive electric generation supplier. All customers are assessed charges for transmission, distribution and a CTC. For customers purchasing electricity from PECO, revenue also reflects the cost of energy. |
| (b) | Other revenue includes transmission revenue from PJM, wholesale revenue and other wholesale energy sales. |
18
 Earnings Conference Call
2
nd
Quarter 2010
July 22, 2010
Exhibit 99.2 |
 2
Forward-Looking Statements
This
presentation
includes
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
these
forward-looking
statements
include
those
discussed
herein
as
well
as
those
discussed
in
(1)
Exelon’s
2009
Annual
Report
on
Form
10-K
in
(a)
ITEM
1A.
Risk
Factors,
(b)
ITEM
7.
Management’s
Discussion
and
Analysis
of
Financial
Condition
and
Results
of
Operations
and
(c)
ITEM
8.
Financial
Statements
and
Supplementary
Data:
Note
18;
(2)
Exelon’s
Second
Quarter
2010
Quarterly
Report
on
Form
10-Q
(to
be
filed
on
July
22,
2010)
in
(a)
Part
II,
Other
Information,
ITEM
1A.
Risk
Factors,
(b)
Part
1,
Financial
Information,
ITEM
2.
Management’s
Discussion
and
Analysis
of
Financial
Condition
and
Results
of
Operations
and
(c)
Part
I
,
Financial
Information,
ITEM
1.
Financial
Statements:
Note
12
and
(3)
other
factors
discussed
in
filings
with
the
Securities
and
Exchange
Commission
(SEC)
by
Exelon
Corporation,
Commonwealth
Edison
Company,
PECO
Energy
Company
and
Exelon
Generation
Company,
LLC
(Companies).
Readers
are
cautioned
not
to
place
undue
reliance
on
these
forward-looking
statements,
which
apply
only
as
of
the
date
of
this
presentation.
None
of
the
Companies
undertakes
any
obligation
to
publicly
release
any
revision
to
its
forward-looking
statements
to
reflect
events
or
circumstances
after
the
date
of
this
presentation.
This
presentation
includes
references
to
adjusted
(non-GAAP)
operating
earnings
and
non-GAAP
cash
flows
that
exclude
the
impact
of
certain
factors.
We
believe
that
these
adjusted
operating
earnings
and
cash
flows
are
representative
of
the
underlying
operational
results
of
the
Companies.
Please
refer
to
the
appendix
to
this
presentation
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
earnings
to
GAAP
earnings.
Please
refer
to
the
footnotes
of
the
following
slides
for
a
reconciliation of non-
GAAP
cash
flows
to
GAAP
cash
flows. |
 3
2017/
2018
2016/
2017
2015/
2016
2014/
2015
PJM RPM Auctions
Delivery Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
Hazardous Air
Pollutants
(HAP)
Criteria
Pollutants
Greenhouse
Gases
Coal
Combustion
By-Products
Compliance with Federal GHG Reporting Rule
Pre-Compliance Period
PSD/BACT and Title V Applies to GHG Emissions from New and Modified Sources
Develop GHG Cap and Trade
Legislation or EPA GHG
Regulations Under CAA
2015: Compliance with GHG
Cap and Trade Legislation or
EPA GHG Regs Under CAA
November 2014: Compliance with MACT
HAP ICR
Pre-Compliance Period
Develop Coal
and Oil MACT
Interim CAIR
Program
Develop Clean Air
Transport Rule
(CATR)
2012: Compliance with CATR (to replace CAIR)
SIP
provisions
developed
in
response
to
revised
NAAQS
(e.g.,
Ozone,
PM
2.5
,
SO2,
NO2)
Compliance
with
CATR
2
Develop Revised NAAQS
and CATR 2
Pre-Compliance Period
2015: Compliance with Federal CCB
Regulations
Develop Coal
Combustion By-
Products Rule
EPA Regulations Will Begin to Affect
Upcoming PJM RPM Auctions
Notes:
Reliability
Pricing
Model
(RPM)
auctions
take
place
annually
in
May.
For
definition
of
the
EPA
regulations
referred
to
on
this
slide,
please
see
the
EPA’s
Terms
of
Environment
(http://www.epa.gov/OCEPAterms/). |
 4
Signs of Power Market Recovery
Forward natural gas prices remain stable
•
In-line with our fundamental view
Heat rates in the spot market are improving
•
We
believe
forward
heat
rate
expansion
is
not
fully
reflected
in
the
market,
particularly
Ni-Hub
Positive results from recent PJM RPM capacity auction
•
Half of our capacity is in premium eastern zones
Exelon has the largest upside to a recovery of any of our merchant peers
|
 5
Nuclear
Uprates
1,300–1,500 MW of new Exelon nuclear capacity by 2017, the
equivalent of a new nuclear plant at roughly half the cost of a
new plant and no incremental operating costs
Leveraging transmission expertise through utility companies,
Exelon Transmission Company and Exelon Generation
Executing regulatory recovery plans at ComEd and PECO with
three active distribution rate cases
Industry-leading energy efficiency and smart grid investments
over the coming years with a regulated return
Organic Growth Opportunities
Transmission
Rate Cases
Smart Grid |
 6
Key Financial Messages
Operating results for 2Q10
•
Operating earnings of $0.99/share
(1)
•
94.8% nuclear capacity factor
•
Continuing to manage O&M costs
Forward power price outlook improving
•
Upside in off-peak prices due to increased load
•
Continued signs of economic recovery in our service areas
Pursuing three rate cases at PECO and ComEd
•
ComEd filed electric distribution rate case on June 30, 2010
•
PECO electric and gas distribution rate cases on schedule
(1)
Refer
to
Earnings
Release
Attachments
for
additional
details
and
to
the
Appendix
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
EPS
to
GAAP
EPS.
Raising 2010 operating earnings guidance to $3.80 -
$4.10/share
(1) |
 7
Operating EPS
(1)
Refer
to
Earnings
Release
Attachments
for
additional
details
and
to
the
Appendix
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
EPS
to
GAAP
EPS.
Strong
performance
at
the
utilities
offset
by
lower
ExGen
margins
driving
quarter
over
quarter
earnings
lower;
however,
2Q10
earnings
exceeded
guidance
of
$0.80-$0.90/share
$0.82
$0.11
$0.69
$0.15
$0.13
$0.18
2009
2010
$1.74
$0.28
$1.35
$0.31
$0.37
$0.31
2009
2010
HoldCo/Other
ExGen
PECO
ComEd
2
nd
Quarter (2Q)
(1)
$0.99
$0.67
GAAP EPS
Year-to-Date (YTD)
(1)
$1.99
$2.24
$2.07
$1.80
$0.99
$1.03 |
 8
Exelon Generation
Operating EPS Contribution
2010
2009
Key Drivers –
2Q10 vs. 2Q09
(1)
Lower energy prices under the PECO
PPA: $(0.04), including CTC offset at
PECO $(0.05) and other pricing of $0.01
Unfavorable market/portfolio conditions:
$(0.05)
Higher nuclear fuel costs: $(0.03)
Favorable RPM capacity pricing: $0.03
Higher O&M costs primarily driven by
inflation: $(0.02)
(1) Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(2) Outage days exclude Salem.
44
57
Refueling
15
21
Non-refueling
2Q10
2Q09
Outage Days
(2)
2Q
YTD
$0.82
$1.74
$0.69
$1.35
Note: PPA = Power Purchase Agreement |
 9
Key Drivers –
2Q10 vs. 2Q09
(1)
IL distribution tax: $0.02
Weather: $0.02
Load growth:
$0.01
Increased storm costs: $(0.01)
ComEd Operating EPS Contribution
(1) Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
2010
2009
2Q
YTD
$0.13
$0.31
2Q10
Actual
Normal
% Change
Heating Degree-Days
519 766 (32)%
Cooling Degree-Days
312 224 39%
$0.18
$0.37 |
 10
PECO Operating EPS Contribution
Key Drivers –
2Q10 vs. 2Q09
(1)
Increased CTC revenue resulting
in lower energy prices paid to
Generation under the PPA, offset
at Generation: $0.05
Weather: $0.03
Increased storm costs: $(0.01)
CTC amortization $(0.04)
2010
2009
(1) Refer to the Earnings Release Attachments for additional details and to the
Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 2Q
YTD
$0.11
$0.28
2Q10
$0.15
$0.31
Actual
Normal
% Change
Heating Degree-Days 299
458 (35)%
Cooling Degree-Days 586
332 77%
|
 11
PECO Load Trends
Philadelphia
Unemployment rate
(1)
9.2%
2010 annualized growth in
gross domestic/metro product
(2)
0.8%
Note: C&I = Commercial & Industrial
2009
(3)
2Q10 2010E
Average Customer Growth
(0.2)%
0.2%
0.0%
Average Use-Per-Customer
(2.1)%
(2.5)%
0.3%
Total Residential
(2.3)%
(2.3)% 0.2%
Small C&I
(2.7)%
(5.1)% (1.8)%
Large C&I
(3.0)%
2.6% 0.9%
All Customer Classes
(2.6)%
(0.7)% 0.1%
(1) Source: U.S Dept. of Labor Preliminary data (June 2010)
(2)
Source: PECO estimate
(3)
Not adjusted for leap year effect
-10.0%
-7.5%
-5.0%
-2.5%
0.0%
2.5%
5.0%
7.5%
10.0%
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10E
4Q10E
-10.0%
-7.5%
-5.0%
-2.5%
0.0%
2.5%
5.0%
7.5%
10.0%
All Customer Classes
Large C&I
Residential
Gross Metro Product
Weather-Normalized
Load
Year-over-Year
(3)
Key Economic Indicators
Weather-Normalized Load |
 12
-10.0%
-7.5%
-5.0%
-2.5%
0.0%
2.5%
5.0%
7.5%
10.0%
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10E
4Q10E
-10.0%
-7.5%
-5.0%
-2.5%
0.0%
2.5%
5.0%
7.5%
10.0%
All Customer Classes
Large C&I
Residential
Gross Metro Product
ComEd Load Trends
Note: C&I = Commercial & Industrial
Chicago
Unemployment rate
(1)
10.2%
2010 annualized growth in
gross domestic/metro product
(2)
2.9%
4/10 Home price index
(3)
(1.5)%
(1) Source: Illinois Dept. of Employment Security (June 2010)
(2)
Source: Global Insight (June 2010)
(3)
Source: S&P Case-Shiller Index
(4)
Not adjusted for leap year effect
2009
(4)
2Q10 2010E
Average Customer Growth
(0.4)%
0.2% 0.2%
Average Use-Per-Customer
(1.0)%
1.4%
0.5%
Total Residential
(1.4)%
1.6% 0.7%
Small C&I
(2.2)%
(0.1)% (0.6)%
Large C&I
(6.7)%
4.3% 2.5%
All Customer Classes
(3.3)%
1.8% 0.8%
Weather-Normalized
Load
Year-over-Year
(4)
Key Economic Indicators
Weather-Normalized Load |
 13
Off-Peak Energy Price Improvement
Both Powder River Basin and Northern Appalachian coal prices have
remained relatively stable over the past quarter
However, NiHub and PJMW Hub off-peak energy prices have increased over
the same period
13
Stabilizing coal prices and recovery in load are providing upside to
prices, particularly in the off-peak
NiHubOff-Peak and Powder River Basin (PRB) Coal
23.00
24.00
25.00
26.00
27.00
28.00
10.50
11.50
12.50
13.50
14.50
15.50
2011 NiHub
2012 NiHub
2011 PRB
2012 PRB
PJMW Hub Off-Peak and Northern Appalachian (NAPP) Coal
35.00
36.00
37.00
38.00
39.00
40.00
41.00
64.00
66.00
68.00
70.00
72.00
74.00
76.00
2011 PJMW
2012 PJMW
2011 NAPP
2012 NAPP |
 14
74.75
134.46
174.29
110.00
143.90
0
500
1,000
1,500
2009/2010
2010/2011
2011/2012
2012/2013
2013/2014
0
100
200
300
PJM RPM Capacity Auction
Note:
Data
contained
on
this
slide
is
rounded.
(1)
Weighted
average
$/MW-Day
would
apply
if
all
generation
cleared
in
the
highlighted
zone.
(2)
All
generation
values
are
approximate
and
not
inclusive
of
wholesale
transactions;
All
capacity
values
are
in
installed
capacity
terms
(summer
ratings)
located
in
the
areas.
(3)
Elwood
contract
expires
on
12/31/12
and
Kincaid
contract
expires
on
2/28/13.
(4)
Reflects
decision
in
December
2010
to
permanently
retire
Cromby
Station
and
Eddystone
Units
1&2
as
of
5/31/11.
None
of
these
933
MW
cleared
in
the
2011/2012
or
2012/2013
auctions.
7%
42%
51%
RTO
EMACC
MACC
8,700 MW
1,500 MW
10,300 MW
(4)
~$400M
Increase
2013/14
RPM
capacity
prices
result
in
a
$400
million
revenue
increase
to
Exelon
over
the
prior
auction;
expect
2014/15
auction
to
result
in
blended
prices
at
least
as
high
(3)
Left axis
PJM RPM Capacity Prices and Auction ($MW-day)
Capacity by Region Eligible for 2014/15
RPM Base Residual Auction
(2) |
 15
2010 Projected Sources and Uses of Cash
($ millions)
Exelon
(9)
Beginning Cash
Balance
(1)
$1,050
Cash Flow from Operations
(1)(2)
1,100
1,025
2,400
4,575
CapEx (excluding Nuclear Fuel, Nuclear
Uprates and Solar Project, Utility Growth
CapEx)
(700)
(400)
(800)
(1,950)
Nuclear Fuel
n/a
n/a
(850)
(850)
Dividend
(3)
(1,400)
Nuclear Uprates and Solar Project
n/a
n/a
(325)
(325)
Utility Growth CapEx
(4)
(225)
(100)
n/a
(325)
Net Financing (excluding Dividend):
Planned Debt Issuances
(5)(6)
500
--
250
750
Planned Debt Retirements
(7)
(225)
(400)
--
(1,025)
Other
(8)
(50)
125
--
0
Ending Cash Balance
(1)
$500
(1)
Excludes counterparty collateral activity.
(2)
Cash Flow from Operations primarily includes net cash flows provided by operating activities and net
cash flows used in investing activities other than capital expenditures. Cash Flow from
Operations for PECO and Exelon includes $550 million for competitive transition charges.
(3)
Assumes 2010 dividend of $2.10/share. Dividends are subject to declaration by the Board of
Directors. (4)
Represents new business and smart grid/smart meter investment.
(5)
Excludes Exelon Generation’s $212 million and ComEd’s $191 million of tax-exempt bonds
that are backed by letters of credit. Excludes PECO’s $225 million Accounts
Receivable (A/R) Agreement with Bank of Tokyo. Assumes PECO’s A/R Agreement is extended in
accordance with its terms beyond September 16, 2010. (6)
Exelon Generation’s financing includes $250 million of debt to refinance a portion of Exelon
Corp’s $400 million maturity. (7)
Excludes Exelon Generation’s and ComEd’s tax-exempt bonds. PECO’s planned
debt retirement of $400 million represents the final retirement of the PECO Energy Transition
Trust. (8)
“Other” includes PECO Parent Receivable, proceeds from options and expected changes in
short-term debt. (9)
Includes cash flow activity from Holding Company, eliminations, and other corporate entities.
|
 16
2010 Operating Earnings Guidance
2010 Revised
Guidance
2010 Prior
Guidance
$0.40 -
$0.50
$2.70 -
$2.90
$3.70 -
$4.00
(1)
ComEd
PECO
Exelon
Generation
ComEd
PECO
Exelon
Generation
Holdco
Holdco
Exelon
$0.60 -
$0.70
Exelon
$3.80 -
$4.10
(1)
$0.60 -
$0.70
$0.45 -
$0.55
$2.80 -
$2.95
(1)
Refer
to
Earnings
Release
Attachments
for
additional
details
and
to
the
Appendix
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
EPS
to
GAAP
EPS.
Key Drivers of Guidance Revision
+
Favorable 2Q performance,
including ExGen revenue net fuel
+
Favorable weather YTD
+
Reaffirmed outlook for remainder of
the year
Revised 2010 operating earnings guidance to $3.80-$4.10/share –
expect 3Q10 results of $1.00 -
$1.10/share
(1) |
 17
Exelon Generation Hedging Disclosures
(as of June 30, 2010)
*
*
*
*
*
*
*
*
*
* |
 18
Important Information
The
following
slides
are
intended
to
provide
additional
information
regarding
the
hedging
program
at
Exelon
Generation
and
to
serve
as
an
aid
for
the
purposes
of
modeling
Exelon
Generation’s
gross
margin
(operating
revenues
less
purchased
power
and
fuel
expense).
The
information
on
the
following
slides
is
not
intended
to
represent
earnings
guidance
or
a
forecast
of
future
events.
In
fact,
many
of
the
factors
that
ultimately
will
determine
Exelon
Generation’s
actual
gross
margin
are
based
upon
highly
variable
market
factors
outside
of
our
control.
The
information
on
the
following
slides
is
as
of
June
30,
2010.
We
update
this
information
on
a
quarterly
basis.
Certain
information
on
the
following
slides
is
based
upon
an
internal
simulation
model
that
incorporates
assumptions
regarding
future
market
conditions,
including
power
and
commodity
prices,
heat
rates,
and
demand
conditions,
in
addition
to
operating
performance
and
dispatch
characteristics
of
our
generating
fleet.
Our
simulation
model
and
the
assumptions
therein
are
subject
to
change.
For
example,
actual
market
conditions
and
the
dispatch
profile
of
our
generation
fleet
in
future
periods
will
likely
differ
–
and
may
differ
significantly
–
from
the
assumptions
underlying
the
simulation
results
included
in
the
slides.
In
addition,
the
forward-
looking
information
included
in
the
following
slides
will
likely
change
over
time
due
to
continued
refinement
of
our
simulation
model
and
changes
in
our
views
on
future
market conditions. |
      19
Portfolio Management Objective
Align Hedging Activities with Financial Commitments
Power Team utilizes several product types
and channels to market
•
Wholesale and retail sales
•
Block products
•
Load-following products
and load auctions
•
Put/call options
Exelon’s hedging program is designed to
protect the long-term value of our
generating fleet and maintain an
investment-grade balance sheet
•
Hedge enough commodity risk to meet future cash
requirements if prices drop
•
Consider: financing policy (credit rating objectives,
capital structure, liquidity); spending (capital and
O&M); shareholder value return policy
Consider market, credit, operational risk
Approach to managing volatility
•
Increase hedging as delivery approaches
•
Have enough supply to meet peak load
•
Purchase fossil fuels as power is sold
•
Choose hedging products based on generation
portfolio –
sell what we own
•
Heat rate options
•
Fuel products
•
Capacity
•
Renewable credits
% Hedged
High End of Profit
Low End of Profit
Open Generation
with LT Contracts
Portfolio
Optimization
Portfolio
Management
Portfolio Management Over Time |
 20
Percentage of Expected
Generation Hedged
•
How many equivalent MW have been
hedged at forward market prices; all hedge
products used are converted to an
equivalent average MW volume
•
Takes ALL
hedges into account whether
they are power sales or financial products
Equivalent MWs Sold
Expected Generation
=
Our
normal
practice
is
to
hedge
commodity
risk
on
a
ratable
basis
over
the
three
years
leading
to
the
spot
market
•
Carry
operational
length
into
spot
market
to
manage
forced
outage
and
load-following
risks
•
By
using
the
appropriate
product
mix,
expected
generation
hedged
approaches
the
mid-90s
percentile
as
the
delivery
period
approaches
•
Participation
in
larger
procurement
events,
such
as
utility
auctions,
and
some
flexibility
in
the
timing
of
hedging
may
mean
the
hedge
program
is
not
strictly
ratable
from
quarter
to
quarter
Exelon Generation Hedging Program |
 21
2010
2011
2012
Estimated Open Gross Margin ($ millions)
(1)(2)
$5,700
$5,300
$5,100
Open gross margin assumes all expected generation is
sold at the Reference Prices listed below
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)
ERCOT North ATC Spark Spread ($/MWh)
(3)
$4.77
$33.17
$44.76
$1.28
$5.34
$32.63
$45.54
$(0.02)
$5.68
$34.22
$46.86
$0.53
Exelon Generation Open Gross Margin and
Reference Prices
(1)
Based on June 30, 2010 market conditions.
(2)
Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding
the impact of decommissioning and other incidental revenues. Open gross margin is estimated
based upon an internal model that is developed by dispatching our expected generation to current market power and fossil fuel prices.
Open gross margin assumes there is no hedging in place other than fixed assumptions for capacity
cleared in the RPM auctions and uranium costs for nuclear power plants. Open gross margin
contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity revenues and
payments. The estimation of open gross margin incorporates management discretion and modeling
assumptions that are subject to change. (3)
ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable O&M.
|
 22
2010
2011
2012
Expected Generation
(GWh)
(1)
167,500
163,000
162,600
Midwest
100,000
98,700
97,500
Mid-Atlantic
58,900
57,000
57,000
South
8,600
7,300
8,100
Percentage of Expected Generation Hedged
(2)
96-99%
86-89%
57-60%
Midwest
96-99
86-89
54-57
Mid-Atlantic
96-99
90-93
59-62
South
97-100
66-69
51-54
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$46.00
$43.50
$44.50
Mid-Atlantic
$36.50
$57.50
$51.00
ERCOT North ATC Spark Spread
$0.00
$(2.00)
$(5.50)
Generation Profile
(1)
Expected generation represents the amount of energy estimated to be generated or purchased through
owned or contracted for capacity. Expected generation is based upon a simulated dispatch
model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products,
and options. Expected generation assumes 10 refueling outages in 2010 and 11 refueling outages
in 2011 and 2012 at Exelon-operated nuclear plants and Salem. Expected generation
assumes capacity factors of 94.1%, 93.2% and 92.9% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected
generation in 2011 and 2012 do not represent guidance or a forecast of future results as Exelon has
not completed its planning or optimization processes for those years. (2)
Percent of expected generation hedged is the amount of equivalent sales divided by the expected
generation. Includes all hedging products, such as wholesale and retail sales of power,
options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.
Current RMR discussions do not impact metrics presented in the hedging disclosure.
(3)
Effective realized energy price is representative of an all-in hedged price, on a per MWh basis,
at which expected generation has been hedged. It is developed by considering the energy
revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium
costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted
at prices other than RPM clearing prices including our load obligations. It can be
compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. |
 23
Gross Margin Sensitivities with Existing Hedges ($ millions)
(1)
Henry Hub Natural Gas
+ $1/MMBtu
-
$1/MMBtu
NI-Hub ATC Energy Price
+$5/MWH
-$5/MWH
PJM-W ATC Energy Price
+$5/MWH
-$5/MWH
Nuclear Capacity Factor
+1% / -1%
2010
$20
$(15)
$10
$(5)
$5
$ -
+/-
$25
2011
$100
$(90)
$75
$(65)
$30
$(25)
+/-
$45
2012
$260
$(245)
$220
$(210)
$130
$(125)
+/-
$45
Exelon Generation Gross Margin Sensitivities
(with Existing Hedges)
(1)
Based on June 30, 2010 market conditions and hedged position. Gas price sensitivities are based on an
assumed gas-power relationship derived from an internal model that is updated
periodically. Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant. Due to correlation of the
various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities
may not be equal to the hedged gross margin impact calculated when correlations between the
various assumptions are also considered. |
 24
95% case
5% case
$6,600
$6,400
$5,100
$7,100
$6,500
$6,600
Exelon
Generation
Gross
Margin
Upside
/
Risk
(with Existing Hedges)
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
2010
2011
2012
(1)
Represents an approximate range of expected gross margin, taking into account hedges in place, between
the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot
market. Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market
inputs, future transactions and potential modeling changes. These ranges of approximate gross margin
in 2011 and 2012 do not represent earnings guidance or a forecast of future results as Exelon
has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market
quotes for power, fuel, load following products, and options as of June 30, 2010.
|
 25
Midwest
Mid-Atlantic
ERCOT
Step 1
Start
with
fleetwide
open
gross
margin
$5.70 billion
Step 2
Determine the mark-to-market value
of energy hedges
100,000GWh * 97% *
($46.00/MWh-$33.17/MWh)
= $1.24 billion
58,900GWh * 97% *
($36.50/MWh-$44.76/MWh)
= $(0.47 billion)
8,600GWh * 98% *
($0.00/MWh-$1.28/MWh)
= $(0.01) billion
Step 3
Estimate hedged gross margin
by
adding open gross margin to mark-to-
market value of energy hedges
Open gross
margin: $5.70 billion
MTM value of energy
hedges: $1.24 billion + $(0.47 billion) + $(0.01) billion
Estimated hedged gross margin:
$6.46 billion
Illustrative Example
of Modeling Exelon Generation 2010 Gross Margin
(with Existing Hedges) |
 26
20
25
30
35
40
45
50
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
50
55
60
65
70
75
80
85
90
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
35
40
45
50
55
60
65
70
75
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
Market
Price
Snapshot
Forward NYMEX Natural Gas
PJM-West and Ni-Hub On-Peak Forward Prices
PJM-West and Ni-Hub Wrap Forward Prices
2011
$5.17
2012 $5.58
Rolling
12
months,
as
of
July
14
, 2010.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
Forward NYMEX Coal
2011
$67.94
2012
$74.45
2011 Ni-Hub $39.68
2012 Ni-Hub
$41.68
2012 PJM-West $53.79
2011 PJM-West
$51.80
2011 Ni-Hub
$24.73
2012 Ni-Hub
$26.61
2012 PJM-West
$39.80
2011 PJM-West
$38.41
th |
 27
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8.0
8.2
8.4
8.6
8.8
9.0
9.2
9.4
9.6
9.8
10.0
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
40
45
50
55
60
65
70
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
Market
Price
Snapshot
2012
$9.09
2011
$9.05
2011
$45.50
2012
$49.38
2011
$5.03
2012
$5.44
Houston Ship Channel Natural Gas
Forward Prices
ERCOT North On-Peak Forward Prices
ERCOT North On-Peak v. Houston Ship Channel
Implied Heat Rate
2011
$6.73
2012
$7.67
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
Rolling
12
months,
as
of
July
14 ,
2010.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
th |
 28
Appendix
*****************
*****************
*****************
***************** |
 29
111.91
148.80
102.04
191.32
174.29
110.00
16.46
133.37
139.73
27.73
226.15
245.00
2008/2009
2009/2010
2010/2011
2011/2012
2012/2013
2013/2014
RTO
MAAC + APS
MAAC
Eastern MAAC
Only shown
if cleared
at separate
price and
generation
is located
in that zone
(1)
RPM Auction Results
Note: Data contained on this slide is rounded.
(1)
MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System.
(2)
All generation values are approximate and not inclusive of wholesale
transactions. (3)
All capacity values are in installed capacity terms (summer ratings) located in the
areas. (4)
Obligation represents the remainder of the ComEd auction load that ends in May
2010. (5)
Obligation consists of load obligations from PECO. PECO PPA expires December
2010. (6)
Elwood contract expires on 12/31/12 and Kincaid contract expires
on 2/28/13.
(7)
Reflects decision in December 2010 to permanently retire Cromby Station and
Eddystone Units 1&2 as of 5/31/11. None of these 933 MW cleared in the
2011/2012 or
2012/2013
auctions.
(8)
Weighted average $/MW-Day would apply if all generation cleared in the
highlighted zones. $134.46
1,500
8,700
(7)
10,300
(6)
Capacity
(3)
2013/2014
2009/2010
2010/2011
2011/2012
2012/2013
in MW
Capacity
(3)
Obligation
Capacity
(3)
Obligation
Capacity
(3)
Capacity
(3)
RTO
12,800
3,800 -
4,100
(5)
23,900
9,300 -
9,400
(4)
23,200
12,100
(6)
EMAAC
9,500
MAAC + APS
11,100
9,300 –
9,400
(5)
MAAC
1,500
Avg ($/MW-Day)
(8)
$143.90
$174.29
$110.00
$74.75
PJM
RPM
Auction
($MW-day)
Exelon
Generation
Eligible
Capacity
within
PJM
Reliability
Pricing
Model
(2) |
 30
ComEd Delivery Service
Rate Case Filing Summary
$396
Total
($2,337
million
revenue
requirement)
(6)
$45
Other adjustments
(5)
$22
Bad debt costs (resets base level of bad debt to 2009 test year)
$55
Pension and Post-retirement health care expenses
(4)
$95
Capital Structure
(3)
: ROE –
11.50% /
Common Equity –
47.33% / ROR –
8.99%
$179
(2)
Rate Base: $7,717 million
(1)
Requested Revenue
Increase
($ in millions)
Primary drivers of rate request are new plant investment, pension/retiree
health care and cost of capital
(1)
Filed
June
30,
2010
based
on
2009
test
year,
including
pro
forma
capital
additions
through
June
2011,
and
certain
other
2010
pro
forma
adjustments.
(2)
Includes
increased
depreciation
expense.
(3)
Requested
capital
structure
does
not
include
goodwill;
ICC
docket
07-0566
allowed
10.3%
ROE,
45.04%
equity
ratio
and
8.36%
ROR.
ROE
includes
0.40%
adder
for
energy
efficiency
incentive.
(4)
Reflects
2010
expense
levels,
compared
to
2007
expense
levels
allowed
in
last
rate
case.
(5)
Includes
reductions
to
O&M
and
taxes
other
than
income,
offset
by
wage
increases,
normalization
of
storm
costs
and
the
Illinois
Electric
Distribution
Tax,
other
O&M
increases,
and
decreases
in
load.
(6)
Net
of
Other
Revenues.
Note:
ROE
=
Return
on
Equity,
ROR
=
Return
on
Rate
Base,
ICC
=
Illinois
Commerce
Commission. |
 31
ComEd Delivery Rate Case
Alternative Regulation (Alt Reg) Proposal
ComEd plans to make a companion Alt Reg filing proposing to recover the costs of
smart grid and other projects outside of the traditional rate case
process •
9-month statutory process
The proposal includes a “flow-through mechanism”
to recover capital carrying costs and
incremental O&M, as incurred
Costs
and
investments
will
be
rolled
in
to
future
rate
cases,
when
they
occur
Assured
savings
to
customers
–
$2
million
on
capped
O&M
costs
for
program
costs
(excluding CARE)
Includes
an
incentive/penalty
mechanism
for
performance
above
or
under
budget
Alt Reg Proposal is permitted under section 9-244 of the IL Public Utilities Act
$30
$15
Man-hole refurbishment and cable replacement
-
$10
Expanded funding for low income CARE programs
(1)
$5
-
Electric Vehicle Fleet Purchase
$55
$40
-
$10
-
$20
Accelerated Smart Grid Deployment
•
190,000 additional AMI Meters and Outage Management
System Interface
•
Accelerated deployment of Distribution Automation
•
Customer Applications
Capital
O&M
$ millions
(1)
Total CARE amount for two-year proposal is $20 million.
|
 32
ComEd Residential Rate Design
Straight Fixed/Variable Proposal
Filing
includes
a
proposal
to
gradually
move
more
of
residential
delivery
bill
to
the
fixed
customer charge, rather than usage-based kwh component through three step
phase-in Current rate design: 37% fixed / 63% variable split
Proposed: 60%/40% split in June 2011, 70%/30% in June 2012, and
80%/20% in June 2013
Mitigates impact of weather and load fluctuations due to weather
and economy
Rate design reflects current cost structure and sends appropriate price signals
•
Fixed costs to be collected via fixed charges (i.e. Customer Charge, Meter
Charge) •
Variable costs to be collected via variable charges (i.e. per kWh)
Eliminates economic disincentive to promote energy efficiency
Proposed Straight Fixed/Variable rate design is consistent with ICC
orders in other recent cases |
 33
3.82
4.73
7.44
7.03
0.73
0.73
0.65
0.60
ComEd Delivery Rate Case
Residential Rate Impacts 2010 to 2011
(1)
(1)
Reflects
change
in
distribution
rates
only.
Assumes
Energy,
Transmission
and
all
other
components
remain
constant
as
of
June
2010,
except
as
noted
above.
(2)
"All
Other"
includes
impact
of
riders
that
are
applicable
to
residential
bills.
Unit rates: cents / kWh
All Other
(2)
Transmission
Energy
Distribution
Approximately
4% increase
July 1, 2010
July 1, 2011
Transmission: Subject to FERC
formula rate annual update
Comments
Energy: Reflects reduced PJM capacity
price that PJM has published for the
June 2011 –
May 2012 planning
period. Energy component may vary
Distribution: As proposed
12.63
13.09
Note: Amounts may not add due to rounding.
Proposed residential rate impact of 7% will be mitigated by impact
of lower capacity prices resulting in an increase of 4%
|
 34
ComEd Delivery Service Rate Case
Tentative Schedule
Delivery
Service
Rate
Case
Filed
–
June
30,
2010
Alt
Reg
Proposal
Filed
–
August
/
September
2010
Intervenor
and
Rebuttal
Testimony
–
4Q
2010
Hearings
–
December
2010
/
January
2011
Administrative
Law
Judge
Order
–
February
2011
Final
Order
Expected
–
May
2011
New
Rates
Effective
–
June
2011
Note:
Dates
are
based
on
typical
approach
to
rate
cases
but
the
ICC
will
set
the
actual
schedule,
which
is
expected
in
3Q
2010. |
 35
6.4
6.9
2.0
2.1
6.7
7.2
2.2
1.9
Transmission
Distribution
ComEd Building Strength
~45%
~43%
8.5%
46.4%
Earned ROE
Equity
(2)
5.5%
45.4%
$8.4
$8.6
$9.4
2008
2009
2011
(Illustrative)
(1)
Provided solely to illustrate possible future outcomes that are based on a number
of different assumptions, including an ROE target, all of which are subject to uncertainties
and should not be relied upon as a forecast of future results. Amounts do not
reflect pro forma adjustments that may be made to determine rate base for rate case filing.
(2)
Equity based on definition provided in most recent ICC distribution rate case order
(book equity less goodwill). Note: Amounts may not add due to rounding.
2010E
$9.0
>10%
>10%
Significant improvement in earned ROE, from
5.5% in 2008 to 8.5% in 2009, targeting at least
10% in 2010
Continued strong operational performance
Filed electric distribution rate case on June 30,
2010
Benefiting from regular transmission updates
through a formula rate plan
Illinois Power Agency’s 2010 procurement
approved by the ICC on April 30
Uncollectibles expense rider tariff approved by
ICC in February 2010
Smart Meter pilot program and rider approved
by ICC and underway
Standard & Poor’s raised credit ratings in
3Q09 and Fitch in 1Q10
ComEd executing on regulatory recovery plan resulting in healthy
increases in earned ROE
Producing
Results
with
Regulatory
Recovery
Plan
End
of
Year
Rate
Base
($
in
billions)
(1) |
 36
Illinois Power Agency (IPA)
RFP Procurement
On April 30, 2010, the ICC approved the bids from the RFP Procurement held
on April 28, 2010, for the remaining ComEd 2010-2011 load (~25% of the total)
and a portion of its 2011-2012 load (~6% of the total)
•
Contracts were awarded to 12 successful bidders
•
$32.54 around-the-clock (ATC) price for 2010-2011 planning year, in
addition to: Financial
Swap
price
(ATC
baseload
energy
only)
of
$50.15
for
June
2010
–
December
2010
and
$51.26
for
January
2011
–
December
2011;
increase
in
notional
quantity
to
3,000
MW
on
June
1,
2010
Delivery
Period
Peak
Off-Peak
June 2010 -
May 2011
5,528
4,344
June 2011 -
May 2012
1,980
549
Volume procured in the 2010 IPA
Procurement Event (GWh)
Note:
Chart
is
for
illustrative
purposes
only.
Data
on
this
slide
is
rounded.
2009 RFP
2009 RFP
2010 RFP
2010 RFP
2011 RFP
2011 RFP
2011 RFP
2012 RFP
2012 RFP
2013 RFP
Financial
Swap
Auction
Contract
June 2009
June 2010
June 2011
June 2012
June 2013
June 2014 |
 37
ComEd Customer Usage Breakdown
Other
2%
Residential
31%
Small C&I
36%
380 Large
C&I
18%
Other Large
C&I
13%
3%
Leisure & Hospitality
9%
Trade, Transportation & Utilities
11%
Finance, Professional &
Business Services
12%
Health & Educational Services
13%
Government
52%
Manufacturing
Limited survey of select Large C&I customers has indicated an increase in
production via longer production runs and additional shifts due to improved
economic conditions for manufacturing-based customers, especially in the
steel and transportation sectors, along with data center expansions.
Customer Usage by Revenue Class
Top
380
Customer
Usage
by
Segment |
 38
PECO –
Electric & Gas Distribution
Rate Case Filing Summary
On March 31, PECO filed electric and gas distribution rate cases
First electric distribution rate case since 1989
•
Act 129 energy efficiency and smart meter costs recovered separately through
rider Last gas delivery rate case in 2008
53.18%
53.18%
Common Equity Ratio
R-2010-2161592
R-2010-2161575
Docket #
2010
(1)
2010
(1)
Test Year
ROE: 11.75%
ROR: 8.95%
ROE: 11.75%
ROR: 8.95%
Requested Returns
$1,100 million
$3,236 million
Rate Base
6.94%
(2)
$316 million
Electric
$44 million
Revenue Requirement Increase
5.28%
2011 Proposed Distribution Price
Increase as % of Overall Customer Bill
Gas
Rate Case Request
(1) With pro forma adjustments.
(2) Excluding Alternative Energy Portfolio Standards and default
service surcharge. Note: Electric and gas rate case filings available on
PAPUC (Pennsylvania Public Utility Commission) website or www.peco.com/know.
PECO executing its post-transition regulatory plan to secure fair and
reasonable returns on its distribution investment |
 39
PECO –
Timeline for Rate Cases
Electric
Gas
Filed:
March 31, 2010
March 31, 2010
Opposing Parties’
Testimony:
July 7, 2010
June 30, 2010
Rebuttal Testimony:
August 3, 2010
July 23, 2010
Hearings:
August 16-20, 2010
August 9-11, 2010
Administrative Law Judge Orders:
November 2, 2010
November 2, 2010
Final Orders Expected:
December 16, 2010
December 16, 2010
New Rates Effective:
January 1, 2011
January 1, 2011
PAPUC has a nine-month process for litigation of the rate case filings
|
 40
5.03
6.26
6.23
0.51
0.70
2.57
8.57
PECO Electric Residential Rate
Increases 2010 to 2011
January 1, 2011
January 1, 2010
Total = 14.7¢
Unit Rates (¢/kWh)
Proposed Total Bill
Increase ~9 %
Total = 16.0¢
AEPS
~0.6%
Smart Meter
~0.7%
Default Service surcharge
mechanism
~(1.8)% Transmission
surcharge
mechanism
~1.3% Energy /
Capacity Competitive Transition
Charge
Transmission
Distribution
Distribution Rate Case ~8.2%
0.47
Energy Efficiency
Surcharge
Breakdown of 2010 to 2011
~9% Increase (On Total Bill)
Notes:
•
Assume results from final procurement in September 2010 are the same as May 2010
procurement. •
Rates effective January 1, 2010 include Act 129 Energy Efficiency surcharge of
2%. •
Low income discounted rates were subsidized in the PPA in 2010 and will be
recovered through distribution rates in 2011. 0.29
|
 41
2.7
3.0
3.3
3.5
0.5
0.6
0.6
1.1
1.1
1.1
1.1
0.6
1.7
0.9
Gas
Competitive Transition Charge (CTC)
Electric Transmission
Electric Distribution
PECO Executing on Transition Plan
Targeted earned ROE of ~11% in 2010; 9-
11% post transition
Electric and gas rate cases filed on March
31, 2010
Selected as 1 of 6 companies to receive
maximum Federal stimulus award of $200
million for smart grid / smart meter
investment
PAPUC approved Smart Meter Plan under
Pennsylvania Act 129 in April 2010
Fixed price PPA with ExGen ends
December 31, 2010
Three of four procurement events for
electricity supply beginning January 1, 2011
have been conducted, including 72% of
2011 residential load
~9 –
11%
Not applicable due to
transition rate structure
Rate Making ROE
Equity
~50 –
53%
$6.3
$5.7
$5.0
2008
2009
2011
(Illustrative)
(2)
(1)
Rate base as determined for rate-making purposes. Amounts do not reflect pro
forma adjustments that may be made to determine rate base for rate case filing
purposes.
(2)
Provided solely to illustrate possible future outcomes that are based on a number
of different assumptions, all of which are subject to uncertainties and should not be
relied upon as a forecast of future results.
$5.1
2010E
PECO is managing through its transition period and is positioned
for
continued strong financial performance post-2010
Actively Engaged in Transition
End of Year Rate Base ($ in billions)
(1) |
 42
PECO Procurement
(1)
See PECO Procurement website (http://www.pecoprocurement.com) for additional
details regarding PECO’s procurement plan and RFP results. (2)
Wholesale prices. No Small/Medium Commercial products were procured in the
June 2009 RFP. (3)
For Large C&I customers who have opted to participate in the 2011
fixed-priced full requirements product. Large Commercial and
Industrial Average price of $77.55/MWh
(2)
100% of fixed-price full requirements procured in May ’10
(3)
Medium Commercial
Sept ’09 / May ’10 RFP aggregate result $77.89/MWh
(2)
Remaining 42% of full requirements to be procured in Sep ‘10
Residential
June ’09 RFP average price of $88.61/MWh
(2)
Sept ’09 RFP average price of $79.96/MWh
(2)
May ‘10 RFP average price of $69.38/MWh
(2)
Remaining 28% of full requirements to be procured in Sep ‘10
Small Commercial
Sept ’09 / May ’10 RFP aggregate result $77.65/MWh
(2)
Remaining 40% of full requirements to be procured in Sep ‘10
85% full requirements
15% full requirements
spot
Medium Commercial
(peak demand >100
kW but <= 500 kW)
Fixed-priced full
requirements
(3)
Hourly full requirements
Large Commercial &
Industrial
(peak
demand >500 kW)
90% full requirements
10% full requirements
spot
75% full requirements
20% block energy
5% energy only spot
Products
Small Commercial
(peak demand <100
kW)
Residential
Customer Class
PECO Procurement Plan
(1)
2011 Supply Procured
Next RFP to be held on September 20, 2010 |
 43
PECO Customer Usage Breakdown
Other
3%
Other Large
C&I
24%
150 Large
C&I
17%
Small C&I
22%
Residential
34%
7%
Other
13%
Transportation, Communication &
Utilities
18%
Health & Educational Services
18%
Manufacturing
22%
Petroleum
2%
Retail Trade
9%
Finance, Insurance & Real Estate
12%
Pharmaceuticals
PECO’s load is relatively diversified by customer class and industry
Customer Usage by Revenue Class
Top 150 Customer Usage by Segment |
 44
ComEd and PECO Accounts Receivable
ComEd A/R
(1)
2Q08
2Q09
2Q10
PECO A/R
(1)
% of AR
$827M
$738M
$784M
(1) Accounts receivable amounts include unbilled receivables and are
gross of allowance for uncollectible accounts at ComEd and PECO and include, for PECO, pledged and
long-term receivables.
>60 days
31-60 days
0-30 days
Note: Data contained on this slide is rounded.
2Q08
2Q09
2Q10
$755M
$894M
$768M |
 45
Sufficient Liquidity
--
--
--
--
Outstanding Facility Draws
(434)
(231)
(3)
(195)
Outstanding Letters of Credit
$7,365
$4,834
$574
$1,000
Aggregate
Bank
Commitments
(1)
6,931
4,603
571
805
Available
Capacity
Under
Facilities
(2)
(187)
--
--
(187)
Outstanding Commercial Paper
$6,744
$4,603
$571
$618
Available Capacity Less Outstanding
Commercial Paper
Exelon
(3)
($ millions)
Available Capacity Under Bank Facilities as of July 14, 2010
Exelon bank facilities are largely untapped
(1) Excludes previous commitment from Lehman Brothers Bank and commitments
from Exelon’s Community and Minority Bank Credit Facility. (2)
Available Capacity Under Facilities represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws. The
amount of commercial paper outstanding does not reduce the available capacity under
the credit agreements. (3) Includes other corporate entities.
|
 46
Projected 2010 Key Credit Measures
14.1x
9.6x
FFO / Interest
Generation /
Corp:
69%
39%
FFO / Debt
55%
70%
Rating Agency Debt Ratio
BBB
A-
A-
BBB-
S&P Credit
Ratings
(3)
BBB+
A
BBB+
BBB+
Fitch Credit
Ratings
(3)
A3
A2
Baa1
Baa1
Moody’s Credit
Ratings
(3)
3.3x
3.6x
FFO / Interest
ComEd:
17%
16%
FFO / Debt
43%
50%
Rating Agency Debt Ratio
4.2x
4.6x
FFO / Interest
PECO:
23%
21%
FFO / Debt
48%
50%
Rating Agency Debt Ratio
29%
47%
Rating Agency Debt Ratio
96%
47%
FFO / Debt
21.2x
11.8x
FFO / Interest
Generation:
48%
37%
6.7x
Without PPA &
Pension / OPEB
(2)
58%
Rating Agency Debt Ratio
27%
FFO / Debt
6.3x
FFO / Interest
Exelon
Consolidated:
With PPA & Pension /
OPEB
(1)
Notes: Exelon and PECO metrics exclude securitization debt. See following slide for FFO (Funds
from Operations)/Interest, FFO/Debt and Adjusted Book Debt Ratio reconciliations to GAAP.
(1)
FFO/Debt metrics include the following standard adjustments: debt equivalents for PV of Operating
Leases, PPAs, unfunded Pension and OPEB obligations (after-tax), Capital Adequacy
for Energy Trading, and other minor debt equivalents. (2)
Excludes items listed in note (1) above.
(3)
Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd
and PECO as of July 15, 2010. |
 47
FFO Calculation and Ratios
+
Other
Non-Cash
items
(1)
-
AFUDC/Cap. Interest
-
Decommissioning activity
+/-
Change in Working Capital
FFO
Calculation
= FFO
-
PECO Transition Bond Principal Paydown
Net Cash Flows provided by Operating Activities
Net Interest Expense
Adjusted Interest
FFO + Adjusted Interest
= Adjusted Interest
+ 6% interest on Present Value (PV) of Operating Leases
+ Interest on imputed debt related to PV of PPA
+ AFUDC & Capitalized interest
-
PECO Transition Bond Interest Expense
FFO
Interest
Coverage
FFO
= Adjusted Debt
+
Off-balance
sheet
debt
equivalents
(2)
-
PECO Transition Bond Principal Balance
+ STD
+ LTD
Debt:
Adjusted Debt
(3)
FFO
Debt
Coverage
Rating Agency Capitalization
Rating Agency Debt
Total Adjusted Capitalization
Adjusted Book Debt
= Total Rating Agency Capitalization
+
Off-balance
sheet
debt
equivalents
(2)
Total Adjusted Capitalization
= Rating Agency Debt
+
Off-balance
sheet
debt
equivalents
(2)
Adjusted Book Debt
= Total Adjusted Capitalization
+ Adjusted Book Debt
+ Preferred Securities of Subsidiaries
+ Total Shareholders' Equity
Capitalization:
= Adjusted Book Debt
-
Transition Bond Principal Balance
+ STD
+ LTD
Debt:
Debt
to
Total
Cap
(1)
Reflects depreciation adjustment for PPAs and operating leases and pension/OPEB
contribution normalization. (2)
Metrics
are
calculated
in
presentation
unadjusted
and
adjusted
for
debt
equivalents
for
PV
of
Operating
Leases,
PPAs,
unfunded
Pension
and
OPEB
obligations
(after-tax),
Capital Adequacy for Energy Trading, and other minor debt equivalents.
(3)
Uses current year-end adjusted debt balance. |
 48
2Q GAAP EPS Reconciliation
NOTE:
All
amounts
shown
are
per
Exelon
share
and
represent
contributions
to
Exelon's
EPS.
Data
contained
on
this
slide
is
rounded.
(0.04)
-
-
(0.02)
(0.02)
2009 severance charges
0.10
-
-
-
0.10
Unrealized gains related to nuclear decommissioning trust funds
(0.01)
(0.01)
-
-
-
NRG acquisition costs
(0.03)
-
-
-
(0.03)
2007 Illinois electric rate settlement
(0.16)
-
-
-
(0.16)
Mark-to-market adjustments from economic hedging activities
0.10
(0.02)
-
0.06
0.06
Non-cash remeasurement of income tax uncertainties and reassessment
of state deferred income taxes
$0.99
$(0.06)
$0.11
$0.17
$0.77
2Q09 GAAP Earnings (Loss) Per Share
$1.03
$(0.03)
$0.11
$0.13
$0.82
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Three
Months
Ended
June
30,
2009
(0.01)
-
-
-
(0.01)
2007 Illinois electric rate settlement
(0.02)
-
-
-
(0.02)
Retirement of fossil generating units
(0.08)
-
-
-
(0.08)
Unrealized losses related to nuclear decommissioning trust funds
(0.11)
-
-
-
(0.11)
Mark-to-market adjustments from economic hedging activities
(0.10)
(0.01)
(0.03)
(0.16)
0.10
Non-cash remeasurement of income tax uncertainties
$0.67
$(0.03)
$0.11
$0.02
$0.57
2Q10 GAAP Earnings (Loss) Per Share
$0.99
$(0.02)
$0.15
$0.18
$0.69
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Three
Months
Ended
June
30,
2010 |
 49
YTD GAAP EPS Reconciliation
0.10
(0.02)
-
0.06
0.06
Non-cash remeasurement of income tax uncertainties and reassessment
of state deferred income taxes
(0.04)
-
-
(0.02)
(0.02)
2009 severance charges
0.05
-
-
-
0.05
Unrealized gains related to nuclear decommissioning trust funds
(0.03)
(0.03)
-
-
-
NRG acquisition costs
(0.06)
-
-
-
(0.06)
2007 Illinois electric rate settlement
0.01
-
-
-
0.01
Mark-to-market adjustments from economic hedging activities
(0.20)
-
-
-
(0.20)
Impairment of certain generating assets
$2.07
$(0.14)
$0.28
$0.35
$1.58
YTD 2009 GAAP Earnings (Loss) Per Share
$2.24
$(0.09)
$0.28
$0.31
$1.74
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Six
Months
Ended
June
30,
2009
(0.01)
-
-
-
(0.01)
2007 Illinois electric rate settlement
(0.10)
(0.01)
(0.03)
(0.16)
0.10
Non-cash remeasurement of income tax uncertainties
(0.03)
-
-
-
(0.03)
Retirement of fossil generating units
(0.05)
-
-
-
(0.05)
Unrealized losses related to nuclear decommissioning trust funds
0.10
-
-
-
0.10
Mark-to-market adjustments from economic hedging activities
(0.10)
(0.02)
(0.02)
(0.02)
(0.04)
Non-cash charge resulting from healthcare legislation
$1.80
$(0.07)
$0.26
$0.19
$1.42
YTD 2010 GAAP Earnings (Loss) Per Share
$1.99
$(0.04)
$0.31
$0.37
$1.35
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Six
Months
Ended
June
30,
2010
NOTE:
All
amounts
shown
are
per
Exelon
share
and
represent
contributions
to
Exelon's
EPS.
Data
contained
on
this
slide
is
rounded. |
 50
2010 Earnings Outlook
Exelon’s
2010
adjusted
(non-GAAP)
operating
earnings
outlook
excludes
the
earnings
effects
of
the
following:
•
Mark-to-market
adjustments
from
economic
hedging
activities
•
Unrealized
gains
and
losses
from
nuclear
decommissioning
trust
fund
investments
to
the
extent
not
offset
by
contractual
accounting
as
described
in
the
notes
to
the
consolidated
financial
statements
•
Significant
impairments
of
assets,
including
goodwill
•
Changes
in
decommissioning
obligation
estimates
•
Costs
associated
with
the
2007
Illinois
electric
rate
settlement
agreement
•
Costs
associated
with
ComEd’s
2007
settlement
with
the
City
of
Chicago
•
Costs
associated
with
the
retirement
of
fossil
generating
units
•
Non-cash
charge
resulting
from
passage
of
Federal
health
care
legislation
•
Non-cash
remeasurement
of
income
tax
uncertainties
•
Other
unusual
items
•
Significant
future
changes
to
GAAP
Operating
earnings
guidance
assumes
normal
weather
for
remainder
of
the
year
Operating
O&M
target
excludes
the
following
items:
•
Exelon
Generation:
Decommissioning
accretion
expense
•
ComEd:
Impact
of
riders,
primarily
Rider
EDA
(Energy
Efficiency
and
Demand
Response Adjustment)
•
PECO:
Impact
of
energy
efficiency
and
smart
grid/meter
riders |