Table of Contents

Exhibit 99.1

 

Contact:		Stacie Frank		FOR IMMEDIATE RELEASE
		Investor Relations
		312-394-3094
		Kathleen Cantillon
		Corporate Communications
		312-394-7417

Exelon Announces Fourth Quarter and Full Year 2011 Results

CHICAGO (January 25, 2012) – Exelon Corporation (NYSE: EXC) announced fourth quarter and full year 2011 consolidated earnings as follows:

 

		Exelon Consolidated Earnings (unaudited)
		Full Year								Fourth Quarter
		2011				2010				2011				2010
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)		$	2,763			$	2,689			$	544			$	631
Diluted Earnings per Share		$	4.16			$	4.06			$	0.82			$	0.96
GAAP Results:
Net Income ($ millions)		$	2,495			$	2,563			$	606			$	524
Diluted Earnings per Share		$	3.75			$	3.87			$	0.91			$	0.79

“Our full year 2011 operating earnings were within our guidance range, as well as above our original expectations for the year,” said John W. Rowe, Exelon’s chairman and CEO. “Despite the impact of adverse economic, market and weather conditions, we achieved our financial commitments and operational excellence across the company.”

Rowe added, “Our significant accomplishments in 2011 included making considerable progress towards completion of our strategic merger with Constellation Energy and continuing to improve our industry-leading environmental position with additions of clean generation assets.”

Fourth Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings declined to $0.82 per share in the fourth quarter of 2011 from $0.96 per share in the fourth quarter of 2010. Earnings in 2011 primarily reflected the following adverse factors:

 

•

The effect on energy margins at Exelon Generation Company, LLC (Generation) of decreased capacity pricing related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market and higher nuclear fuel costs;

 

1

---

Table of Contents

•

Higher operating and maintenance expenses at Generation, including the impact of increased scheduled nuclear refueling outage days;

 

•

The effect of unfavorable weather in the PECO Energy Company (PECO) and Commonwealth Edison Company (ComEd) service territories; and

 

•

Increased depreciation and amortization expense.

These factors were partially offset by:

 

•

The net favorable effect on Generation’s energy margins primarily reflecting market and portfolio conditions in the Mid-Atlantic and Midwest regions;

 

•

The effect of new distribution rates at PECO and ComEd effective January 1, 2011 and June 1, 2011, respectively;

 

•

The effect of 2010 competitive transition charge (CTC) amortization expense, net of collections, at PECO associated with its transition period, which ended on December 31, 2010; and

 

•

Increased distribution revenues at ComEd as a result of the annual reconciliation in the performance-based distribution formula rate tariff and a net reduction in operating and maintenance expenses at ComEd for the allowed recovery of certain 2011 storm costs, both pursuant to the Energy Infrastructure Modernization Act, which became effective in the fourth quarter of 2011.

Adjusted (non-GAAP) operating earnings for the fourth quarter of 2011 do not include the following items (after tax) that were included in reported GAAP earnings:

 

		(in millions)				(per diluted share)
Unrealized gains related to nuclear decommissioning trust (NDT) fund investments to the extent not offset by contractual accounting		$	46			$	0.07
Mark-to-market gains primarily from Generation’s economic hedging activities		$	45			$	0.07
Certain costs associated with the proposed merger with Constellation Energy Group, Inc. (Constellation)		$	(21	)		$	(0.03	)
Financial impacts associated with the retirement of certain Generation fossil generating units		$	(4	)		$	(0.01	)
Non-cash annual remeasurement of state deferred income taxes		$	(4	)		$	(0.01	)

Adjusted (non-GAAP) operating earnings for the fourth quarter of 2010 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		$	(113	)		$	(0.17	)
Unrealized gains related to NDT fund investments to the extent not offset by contractual accounting		$	26			$	0.04
Financial impacts associated with the retirement of certain Generation fossil generating units		$	(17	)		$	(0.03	)
Decrease in costs related to adjustments to asset retirement obligations of ComEd and PECO		$	7			$	0.01
Certain costs related to the acquisition of Exelon Wind		$	(6	)		$	(0.01	)
Costs associated with the 2007 Illinois electric rate settlement agreement		$	(4	)		$	(0.01	)

 

2

---

Table of Contents

Fourth Quarter and Recent Highlights

 

•

Constellation Merger Update: Exelon and Constellation continue to move forward with the regulatory reviews needed to complete their proposed merger. On December 21, 2011, the U.S. Department of Justice (DOJ) cleared the way for the merger in connection with its review of the transaction under the Hart-Scott-Rodino Act. The DOJ’s Antitrust Division filed court papers seeking approval by the U.S. District Court for the District of Columbia with regard to the merger. These papers detail the conditions for the merger agreed to by the DOJ, Exelon and Constellation.

The merger has been approved by the New York Public Service Commission, the Public Utility Commission of Texas and shareholders of Exelon and Constellation. It also requires regulatory approvals by the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission and the Maryland Public Service Commission. In a merger settlement with the State of Maryland, the Maryland Energy Administration (MEA), the City of Baltimore and the Baltimore Building and Construction Trades Council announced December 15, 2011, Exelon, Constellation and Baltimore Gas and Electric Company agreed to provide a package of benefits totaling more than $1 billion and expected to create more than 6,000 jobs in Maryland. Exelon and Constellation continue to expect that the merger will be finalized in early 2012.

 

•

U.S. Environmental Protection Agency (EPA) Mercury and Air Toxics Rule: On December 16, 2011, the EPA signed a final Mercury and Air Toxics Standards (MATS) rule under the Clean Air Act, which will require existing and new coal-fired electricity generating plants to reduce emissions of mercury and other hazardous air pollutants. The MATS rule is largely in line with Exelon’s expectations and requires plants to meet the new standards three years after the rule takes effect, with specific guidelines for an additional one or two years in limited cases. The rule is effective 60 days after it is published in the Federal Register in early 2012.

 

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 34,893 gigawatt-hours (GWh) in the fourth quarter of 2011, compared with 35,115 GWh in the fourth quarter of 2010. The Exelon-operated nuclear plants achieved a 93.0 percent capacity factor for the fourth quarter of 2011 compared with 93.1 percent for the fourth quarter of 2010. The Exelon-operated nuclear plants completed five scheduled refueling outages in the fourth quarter of 2011, compared with completing four scheduled refueling outages in the fourth quarter of 2010. The number of planned refueling outage days totaled 103 in the fourth quarter of 2011 versus 97 days in the fourth quarter of 2010. The number of non-refueling outage days at the Exelon-operated plants totaled 11 days in the fourth quarter of 2011 compared with 18 days in the fourth quarter of 2010.

For the full year 2011, the Exelon-operated nuclear plants achieved an average capacity factor of 93.3 percent, as compared with 93.9 percent for 2010. The average annual capacity factor for the Exelon-operated nuclear fleet has exceeded 93 percent for nine consecutive years.

 

•

Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet (excluding the Wolf Hollow acquisition) was 1.6 percent in the fourth quarter of

 

3

---

Table of Contents

2011, compared with 2.9 percent in the fourth quarter of 2010. The change was largely due to a series of minor forced outages that took place at the Mid-Atlantic peaking units in 2010. The equivalent availability factor for the hydroelectric facilities was 95.9 percent in the fourth quarter of 2011, compared with 99.8 percent in the fourth quarter of 2010. The change was primarily due to a planned inspection outage in December 2011 that was rescheduled from the third quarter.

 

•

Exelon Wind Project Completion: On December 30, 2011, Exelon Wind’s Michigan Wind 2 Project, located in Minden City, Michigan, was completed. The 50-turbine, 90-megawatt (MW) wind project is the first commercial wind project developed by Exelon Wind. Consumers Energy, based in Jackson, Michigan, is purchasing the output from the project through a 20-year renewable energy purchase agreement. The completion of Michigan Wind 2 brings Exelon Wind’s total generation in Michigan to 212 MW. In early 2012, Exelon Wind will begin construction on Harvest II Wind, a 59.4-MW project also located in Michigan.

 

•

Shooting Star Wind Project Acquisition: On December 7, 2011, Exelon Wind and Infinity Wind Holdings, LLC entered into a purchase agreement by which Exelon Wind purchased all of the membership interests in Shooting Star Wind Project, LLC, a 104-MW wind power generation project in Kiowa County, Kansas. The acquisition includes a 20-year power purchase agreement with Mid-Kansas Electric Company for 100 percent of the project’s output. Construction of Shooting Star began in November 2011, and the project is expected to begin full commercial operation in the fourth quarter of 2012.

 

•

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 December 31, 2011 is 88 to 91 percent for 2012, 61 to 64 percent for 2013 and 32 to 35 percent for 2014. 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.

 

•

ComEd Infrastructure Investment, Performance Metrics and Formula Rate Filings: On January 6, 2012, ComEd filed its 10-year, $2.6 billion Infrastructure Investment Plan with the Illinois Commerce Commission (ICC). The filing supports the Energy Infrastructure Modernization Act (EIMA), which was enacted late last year. EIMA includes a policy-based approach that will provide a more predictable ratemaking system and enable utilities to modernize the electric grid and set the stage for fostering economic development while creating and retaining jobs. EIMA also includes a process for determining distribution formula rates that will provide for the recovery of actual costs of service that are prudent and reasonable. ComEd will invest $1.3 billion to strengthen the electric system and another $1.3 billion to add new, digital smart grid and advanced meter technology. ComEd’s plan for 2012 outlines $139 million in capital investments that will be dedicated to improving system reliability and $94 million in smart grid investments.

On December 8, 2011, ComEd made a filing under EIMA to request ICC approval of its proposed multi-year performance metrics plan. The metrics are designed to achieve improvement over baseline values in several performance categories over a 10-year period. The final ICC order must be issued by April 6, 2012.

 

4

---

Table of Contents

On November 8, 2011, ComEd submitted its first filing with the ICC under EIMA for a performance-based formula rate tariff, which initiated a process to establish the model to govern delivery service rate-setting and to set new rates. The initial rate, which is expected to be lower than current rates but will be subject to reconciliation, will take effect within 30 days after the ICC order, which must be issued by May 31, 2012. The filing does not include costs relating to ComEd’s abovementioned Infrastructure Investment Plan. ComEd will file a distribution formula rate plan and updated costs with the ICC each year. ComEd will make its initial reconciliation filing in May 2012, and the adjusted rates will take effect on January 1, 2013 after the ICC’s review. As of December 31, 2011, ComEd recorded its estimated reconciliation for 2011.

 

•

PECO Default Service Plan Filing: On January 13, 2012, PECO filed its Default Service Plan for approval with the Pennsylvania Public Utility Commission (PAPUC). The plan outlines how PECO will purchase electricity for customers not purchasing from a competitive electric generation supplier from June 1, 2013 through May 31, 2015, and proposes several new programs to continue PECO’s support of retail competition in Pennsylvania. To continue to ensure a competitive procurement process for residential customers, PECO proposes to procure electricity through a combination of one-year and two-year fixed full requirements contracts, reduce the amount of time between when the energy is purchased and when it is provided to customers and complete an annual, rather than quarterly, reconciliation of costs for actual versus forecasted energy use. Public hearings for the filing are scheduled in the spring of 2012, with a PAPUC ruling expected in mid-October 2012.

OPERATING COMPANY RESULTS

Generation consists of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations.

Fourth quarter 2011 net income was $446 million compared with $424 million in the fourth quarter of 2010. Fourth quarter 2011 net income included (all after tax) unrealized gains of $46 million related to NDT fund investments, mark-to-market gains of $45 million from economic hedging activities, a $6 million benefit due to the non-cash annual remeasurement of state deferred income taxes, certain costs of $6 million associated with the proposed merger with Constellation and net costs of $4 million associated with the retirement of certain fossil generating units. Fourth quarter 2010 net income included (all after tax) mark-to-market losses of $113 million from economic hedging activities, unrealized gains of $26 million related to NDT fund investments, costs of $17 million associated with the retirement of certain fossil generating units, a charge of $6 million for certain costs associated with the acquisition of Exelon Wind and a charge of $4 million for costs associated with the 2007 Illinois electric rate settlement.

Excluding the effects of these items, Generation’s net income in the fourth quarter of 2011 decreased $179 million compared with the same quarter in 2010. This decrease primarily reflected:

 

•

The impact on energy margins of decreased capacity pricing related to RPM for the PJM market and higher nuclear fuel costs;

 

5

---

Table of Contents

•

Higher operating and maintenance expenses, including the impact of increased scheduled nuclear refueling outage days; and

 

•

Increased depreciation and amortization expense.

These items were partially offset by the net favorable effect on energy margins primarily reflecting market and portfolio conditions in the Mid-Atlantic and Midwest regions.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $39.31 per megawatt-hour (MWh) in the fourth quarter of 2011 compared with $41.45 per MWh in the fourth quarter of 2010.

ComEd consists of electricity transmission and distribution operations in northern Illinois.

ComEd recorded net income of $121 million in the fourth quarter of 2011, compared with net income of $91 million in the fourth quarter of 2010. Fourth quarter net income in 2010 included an after-tax decrease in costs of $6 million associated with an adjustment to ComEd’s asset retirement obligation. Excluding the effects of these items, ComEd’s net income in the fourth quarter of 2011 was up $36 million from the same quarter in 2010, primarily reflecting:

 

•

Increased distribution revenues as a result of the annual reconciliation in the performance-based distribution formula rate tariff pursuant to EIMA, which became effective in the fourth quarter of 2011;

 

•

A net reduction in operating and maintenance expenses for the allowed recovery of certain 2011 storm costs also pursuant to EIMA; and

 

•

The impact of new electric distribution rates effective June 1, 2011.

These items were partially offset by increased other operating and maintenance expenses and the effect of unfavorable weather in ComEd’s service territory.

In the fourth quarter of 2011, heating degree-days in the ComEd service territory were down 20.1 percent relative to the same period in 2010 and were 19.6 percent below normal. Total retail electric deliveries decreased 2.6 percent quarter over quarter.

Weather-normalized retail electric deliveries increased 0.4 percent in the fourth quarter of 2011 relative to 2010, reflecting increases in deliveries to residential and large commercial and industrial (C&I) customers that were partially offset by a decrease in deliveries to small C&I customers. For ComEd, weather had an unfavorable after-tax effect of $7 million on fourth quarter 2011 earnings relative to 2010 and an unfavorable after-tax effect of $6 million relative to normal weather that is incorporated in Exelon’s earnings guidance.

PECO consists of electricity transmission and distribution operations and retail natural gas distribution operations in southeastern Pennsylvania.

PECO’s net income in the fourth quarter of 2011 was $74 million, up from $21 million in the fourth quarter of 2010. Fourth quarter net income in 2011 included certain after-tax costs of $1 million associated with the proposed merger with Constellation. Fourth quarter net income in 2010 included an after-tax decrease in costs of $1 million associated with an adjustment to PECO’s asset retirement obligation. Excluding the effects of these items, PECO’s net income in the fourth quarter of 2011 was up $55 million from the same quarter in 2010, primarily reflecting:

 

6

---

Table of Contents

•

The effect of 2010 CTC amortization expense, net of collections, associated with PECO’s transition period, which ended on December 31, 2010; and

 

•

The impact of new electric and gas distribution rates effective January 1, 2011.

Partially offsetting these items was the effect of unfavorable weather in PECO’s service territory.

In the fourth quarter of 2011, heating degree-days in the PECO service territory were down 22.8 percent from 2010 and were 20.3 percent below normal. Total retail electric deliveries were down 6.1 percent from last year. On the retail gas side, deliveries in the fourth quarter of 2011 were down 22.7 percent from the fourth quarter of 2010.

Weather-normalized retail electric deliveries were down 2.2 percent in the fourth quarter of 2011 relative to 2010, reflecting a decline in large C&I deliveries that was partially offset by increased deliveries to residential and small C&I customers. Weather-normalized retail gas deliveries were up 1.9 percent in the fourth quarter of 2011. For PECO, weather had an unfavorable after-tax effect of $25 million on fourth quarter 2011 earnings relative to 2010 and an unfavorable after-tax effect of $22 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 reconciliation 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 January 25, 2012.

Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on January 25, 2012. 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 40223937. 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 February 8, 2012. The U.S. and Canada call-in number for replays is 855-859-2056, and the international call-in number is 404-537-3406. The conference ID number is 40223937.

Cautionary Statements Regarding Forward-Looking Information

Except for the historical information contained herein, certain of the matters discussed in this communication constitute “forward-looking statements” within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934, both as amended by the Private Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “anticipate,” “estimate,” “expect,” “project,”

 

7

---

Table of Contents

“intend,” “plan,” “believe,” “target,” “forecast,” and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding benefits of the proposed merger of Exelon Corporation (Exelon) and Constellation Energy Group, Inc. (Constellation), integration plans and expected synergies, the expected timing of completion of the transaction, anticipated future financial and operating performance and results, including estimates for growth. These statements are based on the current expectations of management of Exelon and Constellation, as applicable. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication regarding the proposed merger. For example, (1) the companies may be unable to obtain regulatory approvals required for the merger, or required regulatory approvals may delay the merger or result in the imposition of conditions that could have a material adverse effect on the combined company or cause the companies to abandon the merger; (2) conditions to the closing of the merger may not be satisfied; (3) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (4) problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; (5) the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; (6) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations; (7) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (8) the businesses of the companies may suffer as a result of uncertainty surrounding the merger; (9) the companies may not realize the values expected to be obtained for properties expected or required to be divested; (10) the industry may be subject to future regulatory or legislative actions that could adversely affect the companies; and (11) the companies may be adversely affected by other economic, business, and/or competitive factors. Other unknown or unpredictable factors could also have material adverse effects on future results, performance or achievements of Exelon, Constellation or the combined company. Discussions of some of these other important factors and assumptions are contained in Exelon’s and Constellation’s respective filings with the Securities and Exchange Commission (SEC), and available at the SEC’s website at www.sec.gov, including: (1) Exelon’s 2010 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 Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 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 13; (3) Constellation’s 2010 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 12; and (4) Constellation’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 in (a) Part II, Other Information, ITEM 1A. Risk Factors and ITEM 5. Other Information, (b) Part I, 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: Notes to Consolidated Financial Statements, Commitments and Contingencies. These risks, as well as other risks associated with the proposed merger, are more fully discussed in the definitive joint proxy statement/prospectus included in the Registration Statement on Form S-4 that Exelon filed with the SEC and that the SEC declared effective on October 11, 2011 in connection with the proposed merger. In light of these risks, uncertainties, assumptions and factors, the forward-looking events discussed in this

 

8

---

Table of Contents

communication may not occur. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this communication. Neither Exelon nor Constellation undertake any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this communication.

Additional Information and Where to Find It

In connection with the proposed merger between Exelon and Constellation, Exelon filed with the SEC a Registration Statement on Form S-4 that included the definitive joint proxy statement/prospectus. The Registration Statement was declared effective by the SEC on October 11, 2011. Exelon and Constellation mailed the definitive joint proxy statement/prospectus to their respective security holders on or about October 12, 2011. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, BECAUSE THEY CONTAIN IMPORTANT INFORMATION about Exelon, Constellation and the proposed merger. Investors and security holders may obtain copies of all documents filed with the SEC free of charge at the SEC’s website, www.sec.gov. In addition, a copy of the definitive joint proxy statement/prospectus may be obtained free of charge from Exelon Corporation, Investor Relations, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398, or from Constellation Energy Group, Inc., Investor Relations, 100 Constellation Way, Suite 600C, Baltimore, MD 21202.

###

Exelon Corporation is one of the nation’s largest electric utilities with more than $19 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 494,000 customers in the Philadelphia area. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.

 

9

---

Table of Contents

Earnings Release Attachments

Table of Contents

 

Consolidating Statements of Operations—Three Months Ended December 31, 2011 and 2010		1
Consolidating Statements of Operations—Twelve Months Ended December 31, 2011 and 2010		2
Business Segment Comparative Statements of Operations—Generation and ComEd—Three and Twelve Months Ended December 31, 2011 and 2010		3
Business Segment Comparative Statements of Operations—PECO and Other—Three and Twelve Months Ended December 31, 2011 and 2010		4
Consolidated Balance Sheets—December 31, 2011 and December 31, 2010		5
Consolidated Statements of Cash Flows—Twelve Months Ended December 31, 2011 and 2010		6
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Exelon—Three Months Ended December  31, 2011 and 2010		7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Exelon—Twelve Months Ended December  31, 2011 and 2010		8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment—Three Months Ended December 31, 2011 and 2010		9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment—Twelve Months Ended December 31, 2011 and 2010		11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Generation—Three and Twelve Months Ended December 31, 2011 and 2010		13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—ComEd—Three and Twelve Months Ended December 31, 2011 and 2010		14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—PECO—Three and Twelve Months Ended December 31, 2011 and 2010		15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Other—Three and Twelve Months Ended December 31, 2011 and 2010		16
Exelon Generation Statistics—Three Months Ended December 31, 2011, September 30, 2011, June 30, 2011, March  31, 2011 and December 31, 2010		17
Exelon Generation Statistics—Twelve Months Ended December 31, 2011 and 2010		18
ComEd Statistics—Three and Twelve Months Ended December 31, 2011 and 2010		19
PECO Statistics—Three and Twelve Months Ended December 31, 2011 and 2010		20

 

---

Table of Contents

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

 

			$0,00				$0,00				$0,00				$0,00				$0,00
		Three Months Ended December 31, 2011
		Generation				ComEd				PECO				Other (b)				Exelon Consolidated
Operating revenues		$	2,421			$	1,362			$	778			$	(310	)		$	4,251
Operating expenses
Purchased power			381				599				282				(320	)			942
Fuel			306				—				76				—				382
Operating and maintenance			842				239				182				26				1,289
Operating and maintenance for regulatory required programs (a)			—				31				14				—				45
Depreciation and amortization			154				137				53				4				348
Taxes other than income			65				71				40				7				183
Total operating expenses			1,748				1,077				647				(283	)			3,189
Operating income (loss)			673				285				131				(27	)			1,062
Other income and deductions
Interest expense			(43	)			(87	)			(32	)			(19	)			(181	)
Other, net			134				4				2				8				148
Total other income and deductions			91				(83	)			(30	)			(11	)			(33	)
Income (loss) before income taxes			764				202				101				(38	)			1,029
Income taxes			318				81				27				(3	)			423
Net income (loss)		$	446			$	121			$	74			$	(35	)		$	606

 

		Three Months Ended December 31, 2010
		Generation				ComEd				PECO				Other (b)				Exelon Consolidated
Operating revenues		$	2,596			$	1,372			$	1,299			$	(773	)		$	4,494
Operating expenses
Purchased power			602				671				652				(773	)			1,152
Fuel			418				—				123				—				541
Operating and maintenance			731				247				172				10				1,160
Operating and maintenance for regulatory required programs (a)			—				27				17				—				44
Depreciation and amortization			129				130				201				5				465
Taxes other than income			56				68				64				5				193
Total operating expenses			1,936				1,143				1,229				(753	)			3,555
Operating income (loss)			660				229				70				(20	)			939
Other income and deductions
Interest expense			(44	)			(86	)			(34	)			(19	)			(183	)
Other, net			118				10				2				5				135
Total other income and deductions			74				(76	)			(32	)			(14	)			(48	)
Income (loss) before income taxes			734				153				38				(34	)			891
Income taxes			310				62				17				(22	)			367
Net income (loss)		$	424			$	91			$	21			$	(12	)		$	524

 

(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.

(b)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

 

1

---

Table of Contents

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

 

			$0,0.000				$0,0.000				$0,0.000				$0,0.000				$0,0.000
		Twelve Months Ended December 31, 2011
		Generation				ComEd				PECO				Other (b)				Exelon Consolidated
Operating revenues		$	10,568			$	6,056			$	3,720			$	(1,160	)		$	19,184
Operating expenses
Purchased power			2,182				3,035				1,547				(1,220	)			5,544
Fuel			1,528				—				317				(1	)			1,844
Operating and maintenance			3,148				1,086				725				53				5,012
Operating and maintenance for regulatory required programs (a)			—				115				69				—				184
Depreciation and amortization			570				542				202				21				1,335
Taxes other than income			264				296				205				20				785
Total operating expenses			7,692				5,074				3,065				(1,127	)			14,704
Operating income (loss)			2,876				982				655				(33	)			4,480
Other income and deductions
Interest expense			(170	)			(345	)			(134	)			(77	)			(726	)
Loss in equity method investments			(1	)			—				—				—				(1	)
Other, net			122				29				14				34				199
Total other income and deductions			(49	)			(316	)			(120	)			(43	)			(528	)
Income (loss) before income taxes			2,827				666				535				(76	)			3,952
Income taxes			1,056				250				146				5				1,457
Net income (loss)		$	1,771			$	416			$	389			$	(81	)		$	2,495

 

			$00.,00				$00.,00				$00.,00				$00.,00				$00.,00
		Twelve Months Ended December 31, 2010
		Generation				ComEd				PECO				Other (b)				Exelon Consolidated
Operating revenues		$	10,025			$	6,204			$	5,519			$	(3,104	)		$	18,644
Operating expenses
Purchased power			1,853				3,307				2,361				(3,096	)			4,425
Fuel			1,610				—				401				(1	)			2,010
Operating and maintenance			2,812				975				680				(14	)			4,453
Operating and maintenance for regulatory required programs (a)			—				94				53				—				147
Depreciation and amortization			474				516				1,060				25				2,075
Taxes other than income			230				256				303				19				808
Total operating expenses			6,979				5,148				4,858				(3,067	)			13,918
Operating income (loss)			3,046				1,056				661				(37	)			4,726
Other income and deductions
Interest expense			(153	)			(386	)			(193	)			(85	)			(817	)
Other, net			257				24				8				23				312
Total other income and deductions			104				(362	)			(185	)			(62	)			(505	)
Income (loss) before income taxes			3,150				694				476				(99	)			4,221
Income taxes			1,178				357				152				(29	)			1,658
Net income (loss)		$	1,972			$	337			$	324			$	(70	)		$	2,563

 

(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.

(b)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

 

2

---

Table of Contents

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

 

			$6,0.56				$6,0.56				$6,0.56				$6,0.56				$6,0.56				$6,0.56
		Generation
		Three Months Ended December 31,												Twelve Months Ended December 31,
		2011				2010				Variance				2011				2010				Variance
Operating revenues		$	2,421			$	2,596			$	(175	)		$	10,568			$	10,025			$	543
Operating expenses
Purchased power			381				602				(221	)			2,182				1,853				329
Fuel			306				418				(112	)			1,528				1,610				(82	)
Operating and maintenance			842				731				111				3,148				2,812				336
Depreciation and amortization			154				129				25				570				474				96
Taxes other than income			65				56				9				264				230				34
Total operating expenses			1,748				1,936				(188	)			7,692				6,979				713
Operating income			673				660				13				2,876				3,046				(170	)
Other income and deductions
Interest expense			(43	)			(44	)			1				(170	)			(153	)			(17	)
Loss in equity method investments			—				—				—				(1	)			—				(1	)
Other, net			134				118				16				122				257				(135	)
Total other income and deductions			91				74				17				(49	)			104				(153	)
Income before income taxes			764				734				30				2,827				3,150				(323	)
Income taxes			318				310				8				1,056				1,178				(122	)
Net income		$	446			$	424			$	22			$	1,771			$	1,972			$	(201	)

 

			$6,05.a				$6,05.a				$6,05.a				$6,05.a				$6,05.a				$6,05.a
		ComEd
		Three Months Ended December 31,												Twelve Months Ended December 31,
		2011				2010				Variance				2011				2010				Variance
Operating revenues		$	1,362			$	1,372			$	(10	)		$	6,056			$	6,204			$	(148	)
Operating expenses
Purchased power			599				671				(72	)			3,035				3,307				(272	)
Operating and maintenance			239				247				(8	)			1,086				975				111
Operating and maintenance for regulatory required programs (a)			31				27				4				115				94				21
Depreciation and amortization			137				130				7				542				516				26
Taxes other than income			71				68				3				296				256				40
Total operating expenses			1,077				1,143				(66	)			5,074				5,148				(74	)
Operating income			285				229				56				982				1,056				(74	)
Other income and deductions
Interest expense			(87	)			(86	)			(1	)			(345	)			(386	)			41
Other, net			4				10				(6	)			29				24				5
Total other income and deductions			(83	)			(76	)			(7	)			(316	)			(362	)			46
Income before income taxes			202				153				49				666				694				(28	)
Income taxes			81				62				19				250				357				(107	)
Net income		$	121			$	91			$	30			$	416			$	337			$	79

 

(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

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

 

			$00,000				$00,000				$00,000				$00,000				$00,000				$00,000
		PECO
		Three Months Ended December 31,												Twelve Months Ended December 31,
		2011				2010				Variance				2011				2010				Variance
Operating revenues		$	778			$	1,299			$	(521	)		$	3,720			$	5,519			$	(1,799	)
Operating expenses
Purchased power			282				652				(370	)			1,547				2,361				(814	)
Fuel			76				123				(47	)			317				401				(84	)
Operating and maintenance			182				172				10				725				680				45
Operating and maintenance for regulatory required programs (a)			14				17				(3	)			69				53				16
Depreciation and amortization			53				201				(148	)			202				1,060				(858	)
Taxes other than income			40				64				(24	)			205				303				(98	)
Total operating expenses			647				1,229				(582	)			3,065				4,858				(1,793	)
Operating income			131				70				61				655				661				(6)
Other income and deductions
Interest expense			(32	)			(34	)			2				(134	)			(193	)			59
Other, net			2				2				—				14				8				6
Total other income and deductions			(30	)			(32	)			2				(120	)			(185	)			65
Income before income taxes			101				38				63				535				476				59
Income taxes			27				17				10				146				152				(6	)
Net income		$	74			$	21			$	53			$	389			$	324			$	65

 

			$00,000				$00,000				$00,000				$00,000				$00,000				$00,000
		Other (b)
		Three Months Ended December 31,												Twelve Months Ended December 31,
		2011				2010				Variance				2011				2010				Variance
Operating revenues		$	(310	)		$	(773	)		$	463			$	(1,160	)		$	(3,104	)		$	1,944
Operating expenses
Purchased power			(320	)			(773	)			453				(1,220	)			(3,096	)			1,876
Fuel			—				—				—				(1	)			(1	)			—
Operating and maintenance			26				10				16				53				(14	)			67
Depreciation and amortization			4				5				(1	)			21				25				(4	)
Taxes other than income			7				5				2				20				19				1
Total operating expenses			(283	)			(753	)			470				(1,127	)			(3,067	)			1,940
Operating loss			(27	)			(20	)			(7	)			(33	)			(37	)			4
Other income and deductions
Interest expense			(19	)			(19	)			—				(77	)			(85	)			8
Other, net			8				5				3				34				23				11
Total other income and deductions			(11	)			(14	)			3				(43	)			(62	)			19
Loss before income taxes			(38	)			(34	)			(4	)			(76	)			(99	)			23
Income taxes			(3	)			(22	)			19				5				(29	)			34
Net loss		$	(35	)		$	(12	)		$	(23	)		$	(81	)		$	(70	)		$	(11	)

 

(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.

(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

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

 

			$000,00				$000,00
		December 31, 2011				December 31, 2010
ASSETS
Current assets
Cash and cash equivalents		$	1,016			$	1,612
Restricted cash and investments			40				30
Accounts receivable, net
Customer			1,629				1,932
Other			984				1,196
Mark-to-market derivative assets			432				487
Inventories, net
Fossil fuel			208				216
Materials and supplies			656				590
Deferred income taxes			97				—
Regulatory assets			69				10
Other			358				325
Total current assets			5,489				6,398
Property, plant and equipment, net			32,570				29,941
Deferred debits and other assets
Regulatory assets			4,839				4,140
Nuclear decommissioning trust (NDT) funds			6,507				6,408
Investments			766				732
Goodwill			2,625				2,625
Mark-to-market derivative assets			650				409
Pledged assets for Zion Station decommissioning			734				824
Other			912				763
Total deferred debits and other assets			17,033				15,901
Total assets		$	55,092			$	52,240
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings		$	163			$	—
Short-term notes payable — accounts receivable agreement			225				225
Long-term debt due within one year			828				599
Accounts payable			1,444				1,373
Mark-to-market derivative liabilities			112				38
Accrued expenses			1,255				1,040
Deferred income taxes			—				85
Regulatory liabilities			53				44
Dividends payable			349				1
Other			560				835
Total current liabilities			4,989				4,240
Long-term debt			11,799				11,614
Long-term debt to financing trusts			390				390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits			8,351				6,621
Asset retirement obligations			3,884				3,494
Pension obligations			2,194				3,658
Non-pension postretirement benefit obligations			2,263				2,218
Spent nuclear fuel obligation			1,019				1,018
Regulatory liabilities			3,771				3,555
Mark-to-market derivative liabilities			126				21
Payable for Zion Station decommissioning			563				659
Other			1,268				1,102
Total deferred credits and other liabilities			23,439				22,346
Total liabilities			40,617				38,590
Preferred securities of subsidiary			87				87
Shareholders’ equity
Common stock			9,107				9,006
Treasury stock, at cost			(2,327	)			(2,327	)
Retained earnings			10,055				9,304
Accumulated other comprehensive loss, net			(2,450	)			(2,423	)
Total shareholders’ equity			14,385				13,560
Noncontrolling interest			3				3
Total equity			14,388				13,563
Total liabilities and shareholders’ equity		$	55,092			$	52,240

 

5

---

Table of Contents

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

 

		Twelve Months  Ended December 31,
		2011				2010
Cash flows from operating activities
Net income		$	2,495			$	2,563
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization			2,304				2,943
Deferred income taxes and amortization of investment tax credits			1,457				981
Net fair value changes related to derivatives			291				(88	)
Net realized and unrealized losses (gains) on NDT fund investments			14				(105	)
Other non-cash operating activities			782				609
Changes in assets and liabilities:
Accounts receivable			57				(232	)
Inventories			(58	)			(62	)
Accounts payable, accrued expenses and other current liabilities			(254	)			472
Option premiums paid, net			(3	)			(124	)
Counterparty collateral posted, net			(344	)			(155	)
Income taxes			423				(543	)
Pension and non-pension postretirement benefit contributions			(2,360	)			(959	)
Other assets and liabilities			49				(56	)
Net cash flows provided by operating activities			4,853				5,244
Cash flows from investing activities
Capital expenditures			(4,042	)			(3,326	)
Proceeds from nuclear decommissioning trust fund sales			6,139				3,764
Investment in nuclear decommissioning trust funds			(6,332	)			(3,907	)
Acquisitions			(387	)			(893	)
Proceeds from sales of investments			6				28
Purchases of investments			(4	)			(22	)
Change in restricted cash			(3	)			423
Other investing activities			20				39
Net cash flows used in investing activities			(4,603	)			(3,894	)
Cash flows from financing activities
Changes in short-term debt			161				(155	)
Issuance of long-term debt			1,199				1,398
Retirement of long-term debt			(789	)			(828	)
Retirement of long-term debt of variable interest entity			—				(806	)
Dividends paid on common stock			(1,393	)			(1,389	)
Proceeds from employee stock plans			38				48
Other financing activities			(62	)			(16	)
Net cash flows used in financing activities			(846	)			(1,748	)
Increase (decrease) in cash and cash equivalents			(596	)			(398	)
Cash and cash equivalents at beginning of period			1,612				2,010
Cash and cash equivalents at end of period		$	1,016			$	1,612

 

6

---

Table of Contents

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

 

			$0,0				$0,0				$0,0				$0,0				$0,0				$0,0
		Three Months Ended December 31, 2011												Three Months Ended December 31, 2010
		GAAP (a)				Adjustments				Adjusted Non-GAAP				GAAP (a)				Adjustments				Adjusted Non-GAAP
Operating revenues		$	4,251			$	(24	)(c)		$	4,227			$	4,494			$	6	(h)		$	4,500
Operating expenses
Purchased power			942				46	(d)			988				1,152				(145	)(d)			1,007
Fuel			382				27	(c),(d)			409				541				(41	)(d)			500
Operating and maintenance			1,289				(43	)(c),(e)			1,246				1,160				(2	)(c),(i),(j)			1,158
Operating and maintenance for regulatory required programs (b)			45				—				45				44				—				44
Depreciation and amortization			348				(22	)(c)			326				465				(23	)(c)			442
Taxes other than income			183				—				183				193				—				193
Total operating expenses			3,189				8				3,197				3,555				(211	)			3,344
Operating income			1,062				(32	)			1,030				939				217				1,156
Other income and deductions
Interest expense			(181	)			—				(181	)			(183	)			—				(183	)
Other, net			148				(114	)(f)			34				135				(83	)(f)			52
Total other income and deductions			(33	)			(114	)			(147	)			(48	)			(83	)			(131	)
Income before income taxes			1,029				(146	)			883				891				134				1,025
Income taxes			423				(84	(c),(d),(e),  ) (f),(g)			339				367				27	(c),(d),(f),  (h),(i),(j)			394
Net income		$	606			$	(62	)		$	544			$	524			$	107			$	631
Effective tax rate			41.1	%							38.4	%			41.2	%							38.4	%
Earnings per average common share
Basic		$	0.91			$	(0.09	)		$	0.82			$	0.79			$	0.17			$	0.96
Diluted		$	0.91			$	(0.09	)		$	0.82			$	0.79			$	0.17			$	0.96
Average common shares outstanding
Basic			664								664				662								662
Diluted			666								666				663								663
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Retirement of fossil generating units (c)						$	0.01											$	0.03
Mark-to-market impact of economic hedging activities (d)							(0.07	)											0.17
Constellation acquisition costs (e)							0.03												—
Unrealized gains related to NDT fund investments (f)							(0.07	)											(0.04	)
Remeasurement of deferred income taxes (g)							0.01												—
2007 Illinois electric rate settlement (h)							—												0.01
Other acquisition costs (i)							—												0.01
Asset retirement obligation (j)							—												(0.01	)
Total adjustments						$	(0.09	)										$	0.17

 

(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 costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(d)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities.

(e)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation Energy Group, Inc. (Constellation).

(f)	Adjustment to exclude the unrealized gains in 2011 and in 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(g)	Adjustment to exclude the non-cash impacts of the annual remeasurement of state deferred income taxes.

(h)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(i)	Adjustment to exclude certain costs associated with Exelon’s acquisition of Exelon Wind in 2010.

(j)	Adjustment to exclude a decrease in 2010 in ComEd and PECO’s asset retirement obligations.

 

7

---

Table of Contents

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

 

		Twelve Months Ended December 31, 2011												Twelve Months Ended December 31, 2010
		GAAP (a)				Adjustments				Adjusted Non-GAAP				GAAP (a)				Adjustments				Adjusted Non-GAAP
Operating revenues		$	19,184			$	(66	)(c),(d)		$	19,118			$	18,644			$	25	(m),(n)		$	18,669
Operating expenses
Purchased power			5,544				(214	)(e)			5,330				4,425				(3	)(e)			4,422
Fuel			1,844				(78	)(c),(e)			1,766				2,010				32	(e),(o)			2,042
Operating and maintenance			5,012				(124	(c),(d),(f),  )(g),(h),(i)			4,888				4,453				(4	)(c),(f),(h),(p)			4,449
Operating and maintenance for regulatory required programs (b)			184				—				184				147				—				147
Depreciation and amortization			1,335				(87	)(c)			1,248				2,075				(80	)(c)			1,995
Taxes other than income			785				(1	)(c)			784				808				—				808
Total operating expenses			14,704				(504	)			14,200				13,918				(55	)			13,863
Operating income			4,480				438				4,918				4,726				80				4,806
Other income and deductions
Interest expense			(726	)			—				(726	)			(817	)			103	(q)			(714	)
Loss in equity method investments			(1	)			—				(1	)			—				—				—
Other, net			199				(21	)(d),(j)			178				312				(153	)(j),(q)			159
Total other income and deductions			(528	)			(21	)			(549	)			(505	)			(50	)			(555	)
Income before income taxes			3,952				417				4,369				4,221				30				4,251
Income taxes			1,457				149	(c),(d),(e),  (f),(g),(h),  (i),(j),(k),(l)			1,606				1,658				(96	(c),(e),(f),(h),  (j),(m),(n),  )(o),(p),(q)			1,562
Net income		$	2,495			$	268			$	2,763			$	2,563			$	126			$	2,689
Effective tax rate			36.9	%							36.8	%			39.3	%							36.7	%
Earnings per average common share
Basic		$	3.76			$	0.41			$	4.17			$	3.88			$	0.19			$	4.07
Diluted		$	3.75			$	0.41			$	4.16			$	3.87			$	0.19			$	4.06
Average common shares outstanding
Basic			663								663				661								661
Diluted			665								665				663								663
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Retirement of fossil generating units (c)						$	0.05											$	0.08
Wolf Hollow acquisition (d)							(0.03	)											—
Mark-to-market impact of economic hedging activities (e)							0.27												(0.08	)
Asset retirement obligation (f)							0.02												(0.01	)
Constellation acquisition costs (g)							0.07												—
Other acquisition costs (h)							0.01												0.01
Recovery of costs pursuant to distribution rate case order (i)							(0.03	)											—
Unrealized (gains) losses related to NDT fund investments (j)							—												(0.08	)
Charge resulting from Illinois tax rate change legislation (k)							0.04												—
Remeasurement of deferred income taxes (l)							0.01												—
2007 Illinois electric rate settlement (m)							—												0.02
City of Chicago settlement (n)							—												—
Impairment of certain emission allowances (o)							—												0.05
Charge resulting from health care legislation (p)							—												0.10
Non-cash income tax matters (q)							—												0.10
Total adjustments						$	0.41											$	0.19

 

(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 costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(d)	Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

(e)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities.

(f)	Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion and the decrease in PECO’s asset retirement obligation in 2011, and a decrease in ComEd and PECO’s asset retirement obligations in 2010.

(g)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(h)	Adjustment to exclude certain costs associated with Exelon’s acquisition of Exelon Wind in 2010 and Exelon’s acquisition of AVSR 1 in 2011.

(i)	Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(j)	Adjustment to exclude the unrealized losses in 2011 and unrealized gains in 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(k)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(l)	Adjustment to exclude the non-cash charge impacts of the annual remeasurement of state deferred income taxes.

(m)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(n)	Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

(o)	Adjustment to exclude a non-cash charge for the impairment of certain SO2 emission allowances as a result of declining market prices following the release of the EPA’s proposed Transport Rule in the third quarter of 2010.

(p)	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.

(q)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

 

8

---

Table of Contents

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended December 31, 2011 and 2010

 

		Exelon Earnings per Diluted Share				Generation				ComEd				PECO				Other (a)				Exelon
2010 GAAP Earnings (Loss)		$	0.79			$	424			$	91			$	21			$	(12	)		$	524
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities			0.17				113				—				—				—				113
Unrealized Gains Related to NDT Fund Investments (1)			(0.04	)			(26	)			—				—				—				(26	)
Asset Retirement Obligation (2)			(0.01	)			—				(6	)			(1	)			—				(7	)
Retirement of Fossil Generating Units (3)			0.03				17				—				—				—				17
2007 Illinois Electric Rate Settlement			0.01				4				—				—				—				4
Other Acquisition Costs (4)			0.01				6				—				—				—				6
2010 Adjusted (non-GAAP) Operating Earnings (Loss)			0.96				538				85				20				(12	)			631
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (5)			(0.01	)			(5	)			—				—				—				(5	)
Nuclear Fuel Costs (6)			(0.02	)			(15	)			—				—				—				(15	)
Capacity Pricing			(0.13	)			(88	)			—				—				—				(88	)
Market and Portfolio Conditions (7)			0.06				38				—				—				—				38
Transmission Upgrades (8)			—				(8	)			—				—				8				—
ComEd and PECO Margins:
Weather			(0.05	)			—				(7	)			(25	)			—				(32	)
Load			—				—				1				(4	)			—				(3	)
Other Energy Delivery (9)			0.11				—				51				20				—				71
2010 Competitive Transition Charge (CTC), Net (10)			0.07				—				—				50				—				50
Operating and Maintenance Expense:
Labor, Contracting and Materials (11)			(0.07	)			(22	)			(19	)			1				—				(40	)
Planned Nuclear Refueling Outages (12)			(0.02	)			(14	)			—				—				—				(14	)
Other Operating and Maintenance (13)			(0.02	)			(28	)			18				(7	)			6				(11	)
Depreciation and Amortization Expense (14)			(0.04	)			(16	)			(4	)			(6	)			—				(26	)
Income Taxes (15)			—				2				1				7				(11	)			(1	)
Interest Expense, Net			—				1				(1	)			1				2				3
Other (16)			(0.02	)			(24	)			(4	)			18				(4	)			(14	)
2011 Adjusted (non-GAAP) Operating Earnings (Loss)			0.82				359				121				75				(11	)			544
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities			0.07				45				—				—				—				45
Unrealized Gains Related to NDT Fund Investments (1)			0.07				46				—				—				—				46
Retirement of Fossil Generating Units (3)			(0.01	)			(4	)			—				—				—				(4	)
Constellation Acquisition Costs (17)			(0.03	)			(6	)			—				(1	)			(14	)			(21	)
Non-Cash Remeasurement of Deferred Income Taxes (18)			(0.01	)			6				—				—				(10	)			(4	)
2011 GAAP Earnings (Loss)		$	0.91			$	446			$	121			$	74			$	(35	)		$	606

 

(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

 

9

---

Table of Contents

(1)	Reflects the impact of unrealized gains in 2010 and 2011 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)	Reflects a decrease in 2010 of ComEd and PECO’s asset retirement obligations primarily related to transmission and distribution substation assets.

(3)

Primarily reflects accelerated depreciation expense associated with the planned retirement of four generating units, two of which retired on May 31, 2011. In 2011, reflects the net loss attributable to the remaining two units, which includes compensation for operating the units past their planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule.

(4)	Reflects certain costs incurred associated with the acquisition of Exelon Wind in 2010.

(5)	Primarily reflects the impact of increased planned nuclear outage days in the Mid-Atlantic region in 2011 where energy prices are typically higher.

(6)	Reflects the impact of higher nuclear fuel prices.

(7)	Primarily reflects the impact of higher realized energy margins in the Mid-Atlantic region partially offset by the lower realized energy margins in the Midwest, energy margins at Exelon Wind, which was acquired in December 2010, and improved hydro performance.

(8)	Reflects intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(9)

For ComEd, primarily reflects increased distribution revenue pursuant to the 2011 electric distribution rate case order, effective June 1, 2011, and increased distribution revenues as a result of the performance based formula rate tariff pursuant to the Energy Infrastructure Modernization Act (EIMA). For PECO, primarily reflects increased distribution revenue pursuant to the 2010 Pennsylvania electric and natural gas distribution rate case settlements effective January 1, 2011.

(10)	Reflects the impact of 2010 CTC amortization expense, net of recoveries, associated with PECO’s transition period, which ended on December 31, 2010.

(11)	Primarily reflects the impacts of inflation and Exelon Wind, which was acquired in December 2010 (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 12 and 13 below).

(12)	Primarily reflects the impact of increased planned nuclear refueling outage days in 2011, excluding Salem.

(13)

For Generation, primarily reflects the impact of a nuclear insurance credit recorded in 2010 at Generation and increased nuclear refueling outage costs related to Generation’s ownership interests in Salem. For ComEd, primarily reflects a credit for the allowed recovery of certain 2011 storm costs pursuant to EIMA, partially offset by a one-time contribution also pursuant to EIMA.

(14)	Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impacts of Exelon Wind.

(15)

Primarily reflects higher corporate tax rates pursuant to the Illinois tax rate change legislation, partially offset by the transmission and distribution property repairs deduction, production tax credits at Exelon Wind and the incremental impact on the 2010 manufacturing tax deduction associated with the pension contribution made in the first quarter of 2011.

(16)	Primarily reflects realized losses associated with NDT funds at Generation as a result of unfavorable market conditions in 2011, partially offset at PECO by decreased gross receipts tax expense (completely offset by decreased PECO margins above).

(17)	Reflects certain costs incurred associated with Exelon’s proposed acquisition of Constellation.

(18)	Primarily reflects the non-cash impacts of the annual remeasurement of state deferred income taxes to reflect revised estimates of state apportionments.

 

10

---

Table of Contents

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Twelve Months Ended December 31, 2011 and 2010

 

		Exelon Earnings per Diluted Share				Generation				ComEd				PECO				Other (a)				Exelon
2010 GAAP Earnings (Loss)		$	3.87			$	1,972			$	337			$	324			$	(70	)		$	2,563
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities			(0.08	)			(52	)			—				—				—				(52	)
Unrealized Gains Related to NDT Fund Investments (1)			(0.08	)			(52	)			—				—				—				(52	)
Asset Retirement Obligation (2)			(0.01	)			—				(6	)			(1	)			—				(7	)
Retirement of Fossil Generating Units (3)			0.08				50				—				—				—				50
Non-Cash Charge Resulting From Health Care Legislation (4)			0.10				26				12				10				17				65
Non-Cash Remeasurement of Income Tax Uncertainties (5)			0.10				(70	)			106				22				7				65
Impairment of Certain Emission Allowances (6)			0.05				35				—				—				—				35
2007 Illinois Electric Rate Settlement			0.02				12				1				—				—				13
City of Chicago Settlement with ComEd			—				—				2				—				—				2
Acquisition Costs (7)			0.01				7				—				—				—				7
2010 Adjusted (non-GAAP) Operating Earnings (Loss)			4.06				1,928				452				355				(46	)			2,689
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (8)			—				(1	)			—				—				—				(1	)
Nuclear Fuel Costs (9)			(0.08	)			(53	)			—				—				—				(53	)
Capacity Pricing			(0.23	)			(153	)			—				—				—				(153	)
Market and Portfolio Conditions (10)			0.87				577				—				—				—				577
Transmission Upgrades (11)			—				(43	)			—				—				43				—
ComEd and PECO Margins:
Weather			(0.07	)			—				(13	)			(31	)			—				(44	)
Load			(0.02	)			—				(6	)			(6	)			—				(12	)
Other Energy Delivery (12)			0.27				—				91				90				—				181
2010 CTC, Net (13)			(0.12	)			—				—				(75	)			—				(75	)
Discrete Impacts of Distribution Rate Case Order (14)			0.03				—				23				—				—				23
Operating and Maintenance Expense:
Labor, Contracting and Materials (15)			(0.21	)			(77	)			(44	)			(18	)			—				(139	)
Planned Nuclear Refueling Outages (16)			(0.05	)			(35	)			—				—				—				(35	)
Pension and Non-Pension Postretirement Benefits (17)			0.03				12				(1	)			7				3				21
2010 Recovery of Bad Debt Expense at ComEd (18)			(0.06	)			—				(36	)			—				—				(36	)
Other Operating and Maintenance (19)			(0.17	)			(65	)			(23	)			(21	)			(2	)			(111	)
Depreciation and Amortization Expense (20)			(0.13	)			(55	)			(16	)			(18	)			1				(88	)
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (21)			0.07				46				—				—				—				46
Income Taxes (22)			(0.02	)			(17	)			9				20				(28	)			(16	)
Interest Expense, Net (23)			—				(15	)			(6	)			15				3				(3	)
Other (24)			(0.01	)			(47	)			(27	)			70				(4	)			(8	)
2011 Adjusted (non-GAAP) Operating Earnings (Loss)			4.16				2,002				403				388				(30	)			2,763
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities			(0.27	)			(174	)			—				—				—				(174	)
Unrealized Losses Related to NDT Fund Investments (1)			—				(1	)			—				—				—				(1	)
Asset Retirement Obligation (2)			(0.02	)			(18	)			—				2				—				(16	)
Retirement of Fossil Generating Units (3)			(0.05	)			(33	)			—				—				—				(33	)
Constellation Acquisition Costs (25)			(0.07	)			(8	)			—				(1	)			(37	)			(46	)
Other Acquisition Costs (7)			(0.01	)			(5	)			—				—				—				(5	)
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation (26)			(0.04	)			(21	)			(4	)			—				(4	)			(29	)
Wolf Hollow Acquisition (27)			0.03				23				—				—				—				23
Recovery of Costs Pursuant to Distribution Rate Case Order (28)			0.03				—				17				—				—				17
Non-Cash Remeasurement of Deferred Income Taxes (29)			(0.01	)			6				—				—				(10	)			(4	)
2011 GAAP Earnings (Loss)		$	3.75			$	1,771			$	416			$	389			$	(81	)		$	2,495

 

(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

 

11

---

Table of Contents

(1)	Reflects the impact of unrealized gains in 2010 and unrealized losses in 2011 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)	Reflects a decrease in 2010 of ComEd and PECO’s asset retirement obligations primarily related to transmission and distribution substation assets and an increase in 2011 in Generation’s decommissioning obligation for spent nuclear fuel at Zion.

(3)

Primarily reflects accelerated depreciation expense associated with the planned retirement of four generating units, two of which retired on May 31, 2011. Beginning June 1, 2011, reflects the net loss attributable to the remaining two units, which includes compensation for operating the units past their planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule.

(4)	Reflects a non-cash charge in 2010 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.

(5)	Reflects the impact of the 2010 remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and CTCs received by PECO.

(6)	Reflects the impairment of certain SO2 emission allowances as a result of declining market prices following the release of the EPA’s proposed Transport Rule in the third quarter of 2010.

(7)	For 2010, reflects certain costs incurred associated with the acquisition of Exelon Wind and in 2011 reflects certain costs incurred associated with the acquisition of AVSR 1.

(8)	Primarily reflects the impact of increased planned nuclear outage days in the Midwest region in 2011, partially offset by decreased planned nuclear outage days in the Mid-Atlantic region in 2011, where energy prices are typically higher.

(9)	Reflects the impact of higher nuclear fuel prices.

(10)	Primarily reflects the impact of increased realized market prices for the sale of energy in the Mid-Atlantic region due to the end of the PECO PPA, energy margins at Exelon Wind, which was acquired in December 2010, and other favorable market and portfolio conditions in the South and West region.

(11)	Reflects intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(12)

For ComEd, primarily reflects increased distribution revenue pursuant to the 2011 electric distribution rate case order, effective June 1, 2011, and increased distribution revenues as a result of the performance based formula rate tariff pursuant to EIMA. For PECO, primarily reflects increased distribution revenue pursuant to the 2010 Pennsylvania electric and natural gas distribution rate case settlements, effective January 1, 2011.

(13)	Reflects the impact of 2010 CTC recoveries, net of amortization expense, associated with PECO’s transition period, which ended on December 31, 2010.

(14)	Primarily reflects one-time net benefits pursuant to the 2011 ComEd electric distribution rate case order to reestablish previously expensed plant balances and to recognize the estimated recovery of funds for working capital related to the procurement of energy.

(15)	Primarily reflects the impacts of inflation, increased wages and other benefits and the impact of Exelon Wind, which was acquired in December 2010 (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 16 and 19 below).

(16)	Primarily reflects the impact of increased planned nuclear refueling outages in 2011, excluding Salem.

(17)	Primarily reflects the impact of the $2.1 billion pension contribution made in January 2011, partially offset by the lower assumed discount rate and expected return on plan assets used in 2011 as compared to 2010 to calculate the pension and other postretirement benefit obligations and costs.

(18)	Reflects a 2010 credit for the recovery of 2008 and 2009 bad debt expense pursuant to the ICC’s February 2010 approval of a bad debt rider, partially offset by a contribution mandated by Illinois legislation.

(19)

For Generation, primarily reflects additional environmental remediation costs, the impact of a nuclear insurance credit recorded in 2010 and increased nuclear refueling outage costs related to Generation’s ownership interest in Salem. For ComEd, primarily reflects increased storm costs in its service territory and a one-time contribution pursuant to EIMA partially offset by a credit for the allowed recovery of certain 2011 storm costs also pursuant to EIMA. For PECO, primarily reflects increased storm costs in its service territory.

(20)	Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impacts of Exelon Wind.

(21)

Reflects one-time interest and tax benefits associated with a change in the timing of the deduction for the transfer of cash or investments from nonqualified nuclear decommissioning trust funds to qualified decommissioning trust funds pursuant to the Energy Policy Act of 2005 and recently issued Treasury Regulations.

(22)

Primarily reflects a reduction in Generation’s manufacturing deduction benefits (given reduced taxable income as a result of bonus depreciation and the transmission and distribution property repairs deduction), higher corporate tax rates pursuant to the Illinois tax rate change legislation and increased Pennsylvania state tax expense resulting from the expiration of the CTCs and associated tax planning benefits, partially offset by benefits associated with Pennsylvania bonus depreciation, production tax credits at Exelon Wind, and the transmission and distribution property repairs deduction.

(23)

Primarily reflects higher interest expense at Generation and ComEd due to higher outstanding debt, partially offset by lower interest expense at PECO resulting from the retirement of the PECO Energy Transition Trust (PETT) transition bonds on September 1, 2010 and lower outstanding debt at Corporate.

(24)

Primarily reflects increased gross receipts tax expense at Generation (completely offset by increased Generation margins above), realized losses associated with NDT funds at Generation as a result of unfavorable market conditions in 2011 and Illinois electric distribution tax refunds recorded in 2010 at ComEd, partially offset by decreased gross receipts tax expense at PECO (completely offset by decreased PECO margins above).

(25)	Reflects certain costs incurred associated with Exelon’s proposed acquisition of Constellation.

(26)	Reflects the impact of a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(27)	Primarily reflects a non-cash bargain purchase gain (negative goodwill) in connection with the acquisition of Wolf Hollow, net of acquisition costs.

(28)	Reflects one-time benefits pursuant to the ComEd 2011 electric distribution rate case order for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(29)	Primarily reflects the non-cash impacts of the annual remeasurement of state deferred income taxes to reflect revised estimates of state apportionments.

 

12

---

Table of Contents

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

 

			$,000,0				$,000,0				$,000,0				$,000,0				$,000,0				$,000,0
		Generation
		Three Months Ended December 31, 2011												Three Months Ended December 31, 2010
		GAAP (a)				Adjustments				Adjusted Non-GAAP				GAAP (a)				Adjustments				Adjusted Non-GAAP
Operating revenues		$	2,421			$	(24	)(b)		$	2,397			$	2,596			$	6	(g)		$	2,602
Operating expenses
Purchased power			381				46	(c)			427				602				(145	)(c)			457
Fuel			306				27	(b),(c)			333				418				(41	)(c)			377
Operating and maintenance			842				(18	)(b),(d)			824				731				(13	)(b),(h)			718
Depreciation and amortization			154				(22	)(b)			132				129				(23	)(b)			106
Taxes other than income			65				—				65				56				—				56
Total operating expenses			1,748				33				1,781				1,936				(222	)			1,714
Operating income			673				(57	)			616				660				228				888
Other income and deductions
Interest expense			(43	)			—				(43	)			(44	)			—				(44	)
Other, net			134				(114	)(e)			20				118				(83	)(e)			35
Total other income and deductions			91				(114	)			(23	)			74				(83	)			(9	)
Income before income taxes			764				(171	)			593				734				145				879
Income taxes			318				(84	(b),(c),(d),  )(e),(f)			234				310				31	(b),(c),(e),  (g),(h)			341
Net income		$	446			$	(87	)		$	359			$	424			$	114			$	538

 

		Twelve Months Ended December 31, 2011												Twelve Months Ended December 31, 2010
		GAAP (a)				Adjustments				Adjusted Non-GAAP				GAAP (a)				Adjustments				Adjusted Non-GAAP
Operating revenues		$	10,568			$	(66	)(b),(i)		$	10,502			$	10,025			$	21	(g)		$	10,046
Operating expenses
Purchased power			2,182				(214	)(c)			1,968				1,853				(3	)(c)			1,850
Fuel			1,528				(78	)(b),(c)			1,450				1,610				32	(c),(l)			1,642
Operating and maintenance			3,148				(77	(b),(d),(h),  )(i),(j)			3,071				2,812				(18	)(b),(h),(m)			2,794
Depreciation and amortization			570				(87	)(b)			483				474				(80	)(b)			394
Taxes other than income			264				(1	)(c)			263				230				—				230
Total operating expenses			7,692				(457	)			7,235				6,979				(69	)			6,910
Operating income			2,876				391				3,267				3,046				90				3,136
Other income and deductions
Interest expense			(170	)			—				(170	)			(153	)			—				(153	)
Loss in equity method investments			(1	)			—				(1	)			—				—				—
Other, net			122				(21	)(e),(i)			101				257				(155	)(e)			102
Total other income and deductions			(49	)			(21	)			(70	)			104				(155	)			(51	)
Income before income taxes			2,827				370				3,197				3,150				(65	)			3,085
Income taxes			1,056				139	(b),(c),(d),  (e),(f),(h),  (i),(j),(k)			1,195				1,178				(21	(b),(c),(e),(g),  )(h),(l),(m),(n)			1,157
Net income		$	1,771			$	231			$	2,002			$	1,972			$	(44	)		$	1,928

 

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(c)	Adjustment to exclude the mark-to-market impact of Generation’s economic hedging activities.

(d)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(e)	Adjustment to exclude the unrealized gains in 2011 for the three months ended, unrealized losses in 2011 for the twelve months ended and unrealized gains in 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(f)	Adjustment to exclude the non-cash impacts of the annual remeasurement of state deferred income taxes.

(g)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(h)	Adjustment to exclude certain costs associated with Exelon’s acquisition of Exelon Wind in 2010 and Exelon’s acquisition of AVSR 1 in 2011.

(i)	Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

(j)	Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion.

(k)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(l)	Adjustment to exclude a non-cash charge for the impairment of certain SO2 emission allowances as a result of declining market prices following the release of the EPA’s proposed Transport Rule in the third quarter of 2010.

(m)	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.

(n)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

 

13

---

Table of Contents

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

 

			$0000,000				$0000,000				$0000,000				$0000,000				$0000,000				$0000,000
		ComEd
		Three Months Ended December 31, 2011												Three Months Ended December 31, 2010
		GAAP (a)				Adjustments				Adjusted Non-GAAP				GAAP (a)				Adjustments				Adjusted Non-GAAP
Operating revenues		$	1,362			$	—			$	1,362			$	1,372			$	—			$	1,372
Operating expenses
Purchased power			599				—				599				671				—				671
Operating and maintenance			239				—				239				247				10	(c)			257
Operating and maintenance for regulatory required programs (b)			31				—				31				27				—				27
Depreciation and amortization			137				—				137				130				—				130
Taxes other than income			71				—				71				68				—				68
Total operating expenses			1,077				—				1,077				1,143				10				1,153
Operating income			285				—				285				229				(10	)			219
Other income and deductions
Interest expense			(87	)			—				(87	)			(86	)			—				(86	)
Other, net			4				—				4				10				—				10
Total other income and deductions			(83	)			—				(83	)			(76	)			—				(76	)
Income before income taxes			202				—				202				153				(10	)			143
Income taxes			81				—				81				62				(4	)(c)			58
Net income		$	121			$	—			$	121			$	91			$	(6	)		$	85

 

			$0000,0				$0000,0				$0000,0				$0000,0				$0000,0				$0000,0
		Twelve Months Ended December 31, 2011												Twelve Months Ended December 31, 2010
		GAAP (a)				Adjustments				Adjusted Non-GAAP				GAAP (a)				Adjustments				Adjusted Non-GAAP
Operating revenues		$	6,056			$	—			$	6,056			$	6,204			$	4	(f),(g)		$	6,208
Operating expenses
Purchased power			3,035				—				3,035				3,307				—				3,307
Operating and maintenance			1,086				13	(d)			1,099				975				7	(c),(h)			982
Operating and maintenance for regulatory required programs (b)			115				—				115				94				—				94
Depreciation and amortization			542				—				542				516				—				516
Taxes other than income			296				—				296				256				—				256
Total operating expenses			5,074				13				5,087				5,148				7				5,155
Operating income			982				(13	)			969				1,056				(3	)			1,053
Other income and deductions
Interest expense			(345	)			—				(345	)			(386	)			59	(i)			(327	)
Other, net			29				—				29				24				—				24
Total other income and deductions			(316	)			—				(316	)			(362	)			59				(303	)
Income before income taxes			666				(13	)			653				694				56				750
Income taxes			250				—	(d),(e)			250				357				(59	(c),(f),(g),  )(h),(i)			298
Net income		$	416			$	(13	)		$	403			$	337			$	115			$	452

 

(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 decrease in 2010 in ComEd’s asset retirement obligation.

(d)	Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(e)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(f)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(g)	Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

(h)	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.

(i)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

 

14

---

Table of Contents

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

 

			$0000,000				$0000,000				$0000,000				$0000,000				$0000,000				$0000,000
		PECO
		Three Months Ended December 31, 2011												Three Months Ended December 31, 2010
		GAAP (a)				Adjustments				Adjusted Non- GAAP				GAAP (a)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	778			$	—			$	778			$	1,299			$	—			$	1,299
Operating expenses
Purchased power			282				—				282				652				—				652
Fuel			76				—				76				123				—				123
Operating and maintenance			182				(1	)(c)			181				172				1	(d)			173
Operating and maintenance for regulatory required programs (b)			14				—				14				17				—				17
Depreciation and amortization			53				—				53				201				—				201
Taxes other than income			40				—				40				64				—				64
Total operating expenses			647				(1	)			646				1,229				1				1,230
Operating income			131				1				132				70				(1	)			69
Other income and deductions
Interest expense			(32	)			—				(32	)			(34	)			—				(34	)
Other, net			2				—				2				2				—				2
Total other income and deductions			(30	)			—				(30	)			(32	)			—				(32	)
Income before income taxes			101				1				102				38				(1	)			37
Income taxes			27				—	(c)			27				17				—	(d)			17
Net income		$	74			$	1			$	75			$	21			$	(1	)		$	20

 

		Twelve Months Ended December 31, 2011												Twelve Months Ended December 31, 2010
		GAAP (a)				Adjustments				Adjusted Non- GAAP				GAAP (a)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	3,720			$	—			$	3,720			$	5,519			$	—			$	5,519
Operating expenses
Purchased power			1,547				—				1,547				2,361				—				2,361
Fuel			317				—				317				401				—				401
Operating and maintenance			725				1	(c),(d)			726				680				(1	)(d),(e)			679
Operating and maintenance for regulatory required programs (b)			69				—				69				53				—				53
Depreciation and amortization			202				—				202				1,060				—				1,060
Taxes other than income			205				—				205				303				—				303
Total operating expenses			3,065				1				3,066				4,858				(1	)			4,857
Operating income			655				(1	)			654				661				1				662
Other income and deductions
Interest expense			(134	)			—				(134	)			(193	)			36	(f)			(157	)
Other, net			14				—				14				8				2	(f)			10
Total other income and deductions			(120	)			—				(120	)			(185	)			38				(147	)
Income before income taxes			535				(1	)			534				476				39				515
Income taxes			146				—	(c),(d)			146				152				8	(d),(e),(f)			160
Net income		$	389			$	(1	)		$	388			$	324			$	31			$	355

 

(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 certain costs associated with Exelon’s proposed acquisition of Constellation.

(d)	Adjustment to exclude a decrease in 2011 and 2010 in PECO’s asset retirement obligation.

(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.

(f)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

 

15

---

Table of Contents

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

 

			$0000,000				$0000,000				$0000,000				$0000,000				$0000,000				$0000,000
		Other (a)
		Three Months Ended December 31, 2011												Three Months Ended December 31, 2010
		GAAP (b)				Adjustments				Adjusted Non- GAAP				GAAP (b)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	(310	)		$	—			$	(310	)		$	(773	)		$	—			$	(773	)
Operating expenses
Purchased power			(320	)			—				(320	)			(773	)			—				(773	)
Operating and maintenance			26				(24	)(c)			2				10				—				10
Depreciation and amortization			4				—				4				5				—				5
Taxes other than income			7				—				7				5				—				5
Total operating expenses			(283	)			(24	)			(307	)			(753	)			—				(753	)
Operating loss			(27	)			24				(3	)			(20	)			—				(20	)
Other income and deductions
Interest expense			(19	)			—				(19	)			(19	)			—				(19	)
Other, net			8				—				8				5				—				5
Total other income and deductions			(11	)			—				(11	)			(14	)			—				(14	)
Loss before income taxes			(38	)			24				(14	)			(34	)			—				(34	)
Income taxes			(3	)			—	(c),(d)			(3	)			(22	)			—				(22	)
Net loss		$	(35	)		$	24			$	(11	)		$	(12	)		$	—			$	(12	)

 

		Twelve Months Ended December 31, 2011												Twelve Months Ended December 31, 2010
		GAAP (b)				Adjustments				Adjusted Non- GAAP				GAAP (b)				Adjustments				Adjusted Non- GAAP
Operating revenues		$	(1,160	)		$	—			$	(1,160	)		$	(3,104	)		$	—			$	(3,104	)
Operating expenses
Purchased power			(1,220	)			—				(1,220	)			(3,096	)			—				(3,096	)
Fuel			(1	)			—				(1	)			(1	)			—				(1	)
Operating and maintenance			53				(61	)(c)			(8	)			(14	)			8	(f)			(6	)
Depreciation and amortization			21				—				21				25				—				25
Taxes other than income			20				—				20				19				—				19
Total operating expenses			(1,127	)			(61	)			(1,188	)			(3,067	)			8				(3,059	)
Operating income (loss)			(33	)			61				28				(37	)			(8	)			(45	)
Other income and deductions
Interest expense			(77	)			—				(77	)			(85	)			8	(g)			(77	)
Other, net			34				—				34				23				—				23
Total other income and deductions			(43	)			—				(43	)			(62	)			8				(54	)
Loss before income taxes			(76	)			61				(15	)			(99	)			—				(99	)
Income taxes			5				10	(c),(d),(e)			15				(29	)			(24	)(f),(g)			(53	)
Net loss		$	(81	)		$	51			$	(30	)		$	(70	)		$	24			$	(46	)

 

(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(b)	Results reported in accordance with GAAP.

(c)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(d)	Adjustment to exclude the non-cash impacts of the annual remeasurement of state deferred income taxes.

(e)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(f)	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.

(g)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

 

16

---

Table of Contents

EXELON CORPORATION

Exelon Generation Statistics

 

			$,0000,,000				$,0000,,000				$,0000,,000				$,0000,,000				$,0000,,000
		Three Months Ended
		Dec. 31, 2011				Sept. 30, 2011				Jun. 30, 2011				Mar. 31, 2011				Dec. 31, 2010
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic			11,587				12,158				11,172				12,370				11,974
Midwest			23,306				23,887				21,995				22,822				23,141
Total Nuclear Generation			34,893				36,045				33,167				35,192				35,115
Fossil and Renewables
Mid-Atlantic (a) (b)			1,637				1,724				2,054				2,166				2,115
Midwest (c)			188				88				163				157				45
South and West (c)			851				1,463				638				509				93
Total Fossil and Renewables			2,676				3,275				2,855				2,832				2,253
Purchased Power
Mid-Atlantic			739				702				707				750				442
Midwest			1,143				1,756				1,659				1,412				1,776
South and West			1,632				3,815				2,411				2,181				2,632
Total Purchased Power			3,514				6,273				4,777				4,343				4,850
Total Supply by Region
Mid-Atlantic			13,963				14,584				13,933				15,286				14,531
Midwest			24,637				25,731				23,817				24,391				24,962
South and West			2,483				5,278				3,049				2,690				2,725
			41,083				45,593				40,799				42,367				42,218

 

		Three Months Ended
		Dec. 31, 2011				Sept. 30, 2011				Jun. 30, 2011				Mar. 31, 2011				Dec. 31, 2010
Electric Sales (in GWhs)
PECO (d)			—				—				—				—				9,756
Market and Retail (d)			41,083				45,593				40,799				42,367				32,462
Total Electric Sales (d) (e)			41,083				45,593				40,799				42,367				42,218
Average Margin ($/MWh) (f)(g)(h)
Mid-Atlantic		$	56.29			$	57.32			$	58.92			$	59.92			$	51.75
Midwest			34.18				33.15				37.28				39.60				41.14
South and West			(5.24	)			18.57				(3.61	)			(1.49	)			(10.64	)
Average Margin—Overall Portfolio		$	39.31			$	39.19			$	41.59			$	44.30			$	41.45
Around-the-clock Market Prices ($/MWh) (i)
PJM West Hub		$	35.07			$	46.17			$	47.27			$	45.82			$	43.65
NiHub			25.97				37.30				34.94				34.10				27.26
ERCOT North Spark Spread			1.11				36.70				6.73				8.00				(0.69	)

 

(a)	Includes Generation’s proportionate share of the output of its jointly owned generating plants.

(b)	Includes New England generation.

(c)

Includes generation from Exelon Wind, acquired in December, 2010, of 186 GWh, 76 GWh, 154 GWh, 155 GWh and 41 GWh in the Midwest and 394 GWh, 249 GWh, 431 GWh, 358 GWh and 84 GWh in the South and West for the three months ended December 31, 2011, September 30, 2011, June 30, 2011, March 31, 2011 and December 31, 2010, respectively.

(d)	PECO line item represents sales under the PECO PPA. Settlements of the ComEd swap, sales under the Request for Proposal (RFP) and sales to PECO through the competitive procurement process are included within Market and Retail sales.

(e)	Total sales do not include physical trading volume of 1,235 GWh, 1,679 GWh, 1,496 GWh, 1,333 GWh, and 740 GWh for the three months ended December 31, 2011, September 30, 2011, June 30, 2011, March 31, 2011 and December 31, 2010 respectively.

(f)	Excludes retail gas activity, trading portfolio activity and amounts paid related to the Illinois Settlement Legislation and compensation under the reliability-must-run rate schedule.

(g)	Excludes the mark-to-market impact of Generation’s economic hedging activities.

(h)	Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(i)	Represents the average for the quarter.

 

17

---

Table of Contents

EXELON CORPORATION

Exelon Generation Statistics

Twelve Months Ended December 31, 2011 and 2010

 

			$0000,0000				$0000,0000
		December 31, 2011				December 31, 2010
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic			47,287				47,517
Midwest			92,010				92,493
Total Nuclear Generation			139,297				140,010
Fossil and Renewables
Mid-Atlantic (a) (b)			7,580				9,436
Midwest (c)			596				68
South and West (c)			3,462				1,213
Total Fossil and Renewables			11,638				10,717
Purchased Power
Mid-Atlantic			2,898				1,918
Midwest			5,970				7,032
South and West			10,040				12,112
Total Purchased Power			18,908				21,062
Total Supply by Region
Mid-Atlantic			57,765				58,871
Midwest			98,576				99,593
South and West			13,502				13,325
			169,843				171,789

 

			$00,0000				$00,0000
		December 31, 2011				December 31, 2010
Electric Sales (in GWhs)
ComEd (d)			—				5,323
PECO (d)			—				42,003
Market and Retail (d)			169,843				124,463
Total Electric Sales (e)			169,843				171,789
Average Margin ($/MWh) (f)(g)(h)
Mid-Atlantic		$	58.15			$	42.67
Midwest			35.98				40.98
South and West			5.18				(9.83	)
Average Margin—Overall Portfolio		$	41.07			$	37.62
Around-the-clock Market Prices ($/MWh) (i)
PJM West Hub		$	43.56			$	45.93
NiHub			33.07				33.09
ERCOT North Spark Spread			11.88				2.31

 

(a)	Includes Generation’s proportionate share of the output of its jointly owned generating plants.

(b)	Includes New England generation.

(c)	Includes generation from Exelon Wind, acquired in December, 2010, of 570 GWhs and 41 GWhs in the Midwest and 1,432 GWhs and 84 GWhs in the South for the years ended December 31, 2011 and 2010, respectively.

(d)	ComEd and PECO line items represent sales under the 2006 ComEd Auction and PECO PPA. Settlements of the ComEd swap, sales under the RFP and sales to PECO through the competitive procurement process are included within Market and Retail sales.

(e)	Total sales do not include physical trading volume of 5,742 GWhs and 3,625 GWhs for the years ended December 31, 2011 and 2010, respectively.

(f)	Excludes retail gas activity, trading portfolio activity, the $57 million lower of cost or market impairment of certain S02 allowances, amounts paid related to the Illinois Settlement Legislation and compensation under the reliability-must-run rate schedule.

(g)	Excludes the mark-to-market impact of Generation’s economic hedging activities.

(h)	Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(i)	Represents the average for the years ended December 31, 2011 and 2010, respectively.

 

18

---

Table of Contents

EXELON CORPORATION

ComEd Statistics

Three Months Ended December 31, 2011 and 2010

 

		Electric Deliveries (in GWhs)																Revenue (in millions)
		2011				2010				% Change				Weather- Normal %  Change				2011				2010				% Change
Retail Deliveries and Sales (a)
Residential			6,166				6,393				(3.6	)%			1.2	%		$	764			$	761				0.4	%
Small Commercial & Industrial			7,632				7,929				(3.7	)%			(1.2	)%			340				366				(7.1	)%
Large Commercial & Industrial			6,721				6,725				(0.1	)%			1.8	%			95				91				4.4	%
Public Authorities & Electric Railroads			316				346				(8.7	)%			(3.1	)%			12				14				(14.3	)%
Total Retail			20,835				21,393				(2.6	)%			0.4	%			1,211				1,232				(1.7	)%
Other Revenue (b)																			151				140				7.9	%
Total Electric Revenue																		$	1,362			$	1,372				(0.7	)%
Purchased Power																		$	599			$	671				(10.7	)%

 

														% Change
Heating and Cooling Degree-Days		2011				2010				Normal				From 2010				From Normal
Heating Degree-Days			1,832				2,292				2,278				(20.1	)%			(19.6	)%
Cooling Degree-Days			14				15				7				(6.7	)%			100.0	%

Twelve Months Ended December 31, 2011 and 2010

 

		Electric Deliveries (in GWhs)																Revenue (in millions)
		2011				2010				% Change				Weather- Normal Change				2011				2010				% Change
Retail Deliveries and Sales (a)
Residential			28,273				29,171				(3.1	)%			(1.3	)%		$	3,510			$	3,549				(1.1	)%
Small Commercial & Industrial			32,281				32,904				(1.9	)%			(0.8	)%			1,517				1,639				(7.4	)%
Large Commercial & Industrial			27,732				27,717				0.1	%			0.6	%			383				397				(3.5	)%
Public Authorities & Electric Railroads			1,235				1,273				(3.0	)%			(1.2	)%			50				62				(19.4	)%
Total Retail			89,521				91,065				(1.7	)%			(0.5	)%			5,460				5,647				(3.3	)%
Other Revenue (b)																			596				557				7.0	%
Total Electric Revenue																		$	6,056			$	6,204				(2.4	)%
Purchased Power																		$	3,035			$	3,307				(8.2	)%

 

														% Change
Heating and Cooling Degree-Days		2011				2010				Normal				From 2010				From Normal
Heating Degree-Days			6,134				5,991				6,362				2.4	%			(3.6	)%
Cooling Degree-Days			1,036				1,181				855				(12.3	)%			21.2	%

 

Number of Electric Customers		2011				2010
Residential			3,448,481				3,438,677
Small Commercial & Industrial			365,824				363,393
Large Commercial & Industrial			2,032				2,005
Public Authorities & Electric Railroads			4,797				5,078
Total			3,821,134				3,809,153

 

(a)

Reflects delivery revenues and volumes from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges. 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.

 

19

---

Table of Contents

EXELON CORPORATION

PECO Statistics

Three Months Ended December 31, 2011 and 2010

 

		Electric and Gas Deliveries																Revenue (in millions)
		2011				2010				% Change				Weather- Normal %  Change				2011				2010				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			2,937				3,124				(6.0	)%			1.1	%		$	392			$	444				(11.7	)%
Small Commercial & Industrial			1,884				1,958				(3.8	)%			0.3	%			114				233				(51.1	)%
Large Commercial & Industrial			3,665				3,975				(7.8	)%			(6.8	)%			45				327				(86.2	)%
Public Authorities & Electric Railroads			235				226				4.0	%			8.8	%			9				22				(59.1	)%
Total Retail			8,721				9,283				(6.1	)%			(2.2	)%			560				1,026				(45.4	)%
Other Revenue (b)																			63				61				3.3	%
Total Electric Revenue																			623				1,087				(42.7	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales			15,257				19,730				(22.7	)%			1.9	%			147				205				(28.3	)%
Transportation and Other			6,776				7,253				(6.6	)%			(4.5	)%			8				7				14.3	%
Total Gas			22,033				26,983				(18.3	)%			0.1	%			155				212				(26.9	)%
Total Electric and Gas Revenues																		$	778			$	1,299				(40.1	)%
Purchased Power																		$	282			$	652				(56.7	)%
Fuel																			76				123				(38.2	)%
Total Purchased Power and Fuel																		$	358			$	775				(53.8	)%

 

														% Change
Heating and Cooling Degree-Days		2011				2010				Normal				From 2010				From Normal
Heating Degree-Days			1,302				1,686				1,634				(22.8	)%			(20.3	)%
Cooling Degree-Days			14				19				21				(26.3	)%			(33.3	)%

Twelve Months Ended December 31, 2011 and 2010

 

		Electric and Gas Deliveries																Revenue (in millions)
		2011				2010				% Change				Weather- Normal % Change				2011				2010				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			13,687				13,913				(1.6	)%			1.7	%		$	1,934			$	2,069				(6.5	)%
Small Commercial & Industrial			8,321				8,503				(2.1	)%			(0.7	)%			584				1,060				(44.9	)%
Large Commercial & Industrial			15,677				16,372				(4.2	)%			(3.3	)%			304				1,362				(77.7	)%
Public Authorities & Electric Railroads			945				925				2.2	%			4.6	%			38				89				(57.3	)%
Total Retail			38,630				39,713				(2.7	)%			(0.9	)%			2,860				4,580				(37.6	)%
Other Revenue (b)																			249				255				(2.4	)%
Total Electric Revenue																			3,109				4,835				(35.7	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales			54,239				56,833				(4.6	)%			1.2	%			575				656				(12.3	)%
Transportation and Other			28,204				30,911				(8.8	)%			(7.5	)%			36				28				28.6	%
Total Gas			82,443				87,744				(6.0	)%			(1.8	)%			611				684				(10.7	)%
Total Electric and Gas Revenues																		$	3,720			$	5,519				(32.6	)%
Purchased Power																		$	1,547			$	2,361				(34.5	)%
Fuel																			317				401				(20.9	)%
Total Purchased Power and Fuel																		$	1,864			$	2,762				(32.5	)%

 

														% Change
Heating and Cooling Degree-Days		2011				2010				Normal				From 2010				From Normal
Heating Degree-Days			4,157				4,396				4,638				(5.4	)%			(10.4	)%
Cooling Degree-Days			1,617				1,817				1,292				(11.0	)%			25.2	%

 

Number of Electric Customers		2011				2010				Number of Gas Customers		2011				2010
Residential			1,415,681				1,411,643			Residential			451,382				448,391
Small Commercial & Industrial			157,137				156,865			Commercial & Industrial			41,373				41,303
Large Commercial & Industrial			3,110				3,071			Total Retail			492,755				489,694
Public Authorities & Electric Railroads			1,122				1,102			Transportation			879				838
Total			1,577,050				1,572,681			Total			493,634				490,532

 

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers purchasing electricity directly from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM, and wholesale electric and gas revenues.

(c)

Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas directly from a competitive natural gas supplier as all customers are assessed distribution charges. The cost of natural gas is charged to customers purchasing natural gas from PECO.

 

20