•GAAP Net Income of $1.23 per share and Adjusted (non-GAAP) Operating Earnings of $1.09 per share for the third quarter of 2021
•Narrowing guidance range for full year 2021 Adjusted (non-GAAP) Operating Earnings from $2.60-$3.00 per share to $2.70-$2.90 per share
•Strong utility reliability performance - every utility achieved top decile in outage frequency, every utility achieved top quartile in outage duration, and all gas utilities achieved top decile in gas odor response
•Generation’s nuclear fleet capacity factor was 96.0% (owned and operated units)
•Federal Energy Regulatory Commission (FERC) approved the planned separation of Generation in August
•Exelon Generation purchased EDF’s 49.99% equity interest in CENG for a net purchase price of $885 million
•Passage of the Illinois Clean Energy Law in September preserved operation of Byron and Dresden generating stations, strengthening the state’s clean energy leadership; the law also contains requirements associated with ComEd’s transition away from the performance-based electric distribution formula rate
•Delmarva Power Maryland filed an electric distribution rate case with the Maryland Public Service Commission (MDPSC) in September seeking an increase in base rates to support an updated depreciation study and continued investments in the system to enhance grid reliability and customer service
•An order from the Delaware Public Service Commission (DPSC) in Delmarva Power Delaware’s electric distribution rate case was received in September
CHICAGO (Nov. 3, 2021) — Exelon Corporation (Nasdaq: EXC) today reported its financial results for the third quarter of 2021.
“We achieved several critical milestones during the third quarter, starting with passage of landmark clean energy legislation in Illinois that preserves our nuclear fleet and puts the state on a path to zero emissions by 2045,” said Chris Crane, president and CEO of Exelon. “We also remain on track to complete the separation of our utility and competitive generation businesses in the first quarter of next year, having recently named executive leadership, secured approval from the Federal Energy Regulatory Commission
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and completed acquisition of EDF’s stake in three of our nuclear plants. We continue to live our values by launching a $36 million Racial Equity Capital Fund to help minority-owned businesses in our communities finance their growth and establishing a $3 million scholarship program for local students attending Historically Black Colleges and Universities.”
“Adjusted (non-GAAP) Operating Earnings of $1.09 per share in the third quarter was $0.05 ahead of the same period last year, driven in part by rate adjustments resulting from our continued investments at the utilities to improve reliability and service for customers,” said Joseph Nigro, senior executive vice president and CFO of Exelon. “Our ongoing capital investments in technology and infrastructure continue to drive strong financial and operational results across our utilities, with each of our electric and gas distribution companies achieving top 10 percent rankings for outage frequency and high marks for customer satisfaction relative to peers. Our Generation fleet also continued to perform at a high level, with nuclear achieving a capacity factor of 96 percent and the Power fleet at a 99.4 percent dispatch match and 95.8 percent wind/solar energy capture rate. Based on our results to date, we are narrowing our 2021 earnings per share guidance range to $2.70 to $2.90 per share from $2.60 to $3.00 per share.”
Third Quarter 2021
Exelon's GAAP Net Income for the third quarter of 2021 increased to $1.23 per share from $0.51 GAAP Net Income per share in the third quarter of 2020. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 increased to $1.09 per share from $1.04 per share in the third quarter of 2020. For the reconciliations of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings, refer to the tables beginning on page 6.
Adjusted (non-GAAP) Operating Earnings in the third quarter of 2021 primarily reflect:
•Higher utility earnings primarily due to higher electric distribution earnings at ComEd from higher rate base and higher allowed ROE due to an increase in treasury rates; the favorable impacts of the multi-year plan at BGE; and regulatory rate increases at PHI.
•Lower Generation earnings primarily due to higher net unrealized and realized losses on equity investments, lower capacity revenues, and increased nuclear outage days, partially offset by increased revenue from ZECs in New York and higher realized gains on nuclear decommissioning trust (NDT) funds.
Operating Company Results1
ComEd
ComEd's third quarter of 2021 GAAP Net Income increased to $220 million from a GAAP Net Income of $196 million in the third quarter of 2020. ComEd's Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 increased to $224 million from $197 million in the third quarter of 2020, primarily due to higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates. Due to revenue decoupling, ComEd's distribution earnings are not affected by actual weather or customer usage patterns.
___________
1Exelon’s five business units include ComEd, which consists of electricity transmission and distribution operations in northern Illinois; PECO, which consists of electricity transmission and distribution operations and retail natural gas distribution operations in southeastern Pennsylvania; BGE, which consists of electricity transmission and distribution operations and retail natural gas distribution operations in central Maryland; PHI, which consists of electricity transmission and distribution operations in the District of Columbia and portions of Maryland, Delaware, and New Jersey and retail natural gas distribution operations in northern Delaware; and Generation, which consists of owned and contracted electric generating facilities and wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products and risk management services.
2
PECO
PECO’s third quarter of 2021 GAAP Net Income decreased to $111 million from $138 million in the third quarter of 2020. PECO's Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 decreased to $114 million from $141 million in the third quarter of 2020, primarily due to an increase in storm cost activity, net of tax repair deductions.
BGE
BGE’s third quarter of 2021 GAAP Net Income decreased to $36 million from $53 million in the third quarter of 2020. BGE's Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 decreased to $40 million from $54 million in the third quarter of 2020. The decrease includes the impacts of higher depreciation and amortization expense partially offset by the favorable impacts of the multi-year plan. Due to revenue decoupling, BGE's distribution earnings are not affected by actual weather or customer usage patterns.
PHI
PHI’s third quarter of 2021 GAAP Net Income increased to $266 million from $216 million in the third quarter of 2020. PHI’s Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 increased to $272 million from $220 million in the third quarter of 2020, primarily due to distribution rate increases at DPL and Pepco. Due to revenue decoupling, PHI's distribution earnings related to Pepco Maryland, DPL Maryland, Pepco District of Columbia, and ACE are not affected by actual weather or customer usage patterns.
Generation
Generation's third quarter of 2021 GAAP Net Income increased to $607 million from $49 million in the third quarter of 2020. Generation's Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 decreased to $427 million from $456 million in the third quarter of 2020, primarily due to higher net unrealized and realized losses on equity investments, lower capacity revenues, and increased nuclear outage days, partially offset by increased revenue from ZECs in New York and higher realized gains on NDT funds.
As of Sept. 30, 2021, the percentage of expected generation hedged is 96%-99% for the remainder of 2021.
Recent Developments and Third Quarter Highlights
•Planned Separation: On Aug. 24, 2021, the FERC approved the planned separation of Generation and on Sept. 23, 2021, Exelon received a private letter ruling from the Internal Revenue Service (IRS) confirming the tax-free treatment of the planned separation. Exelon is targeting the completion of the separation in the first quarter of 2022.
•Clean Energy Law and Reversal of Decision to Early Retire Byron and Dresden Nuclear Facilities: On Sept. 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity including the authorization of 54.5 million carbon mitigation credits for qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027 in which the Byron, Dresden and Braidwood nuclear plants will be eligible to participate in the procurement process. With the passage of the Clean Energy Law, Generation has reversed its decision to permanently cease generation operations at the Byron and Dresden nuclear plants
3
given the opportunity for additional revenue. In addition, Generation no longer considers the Braidwood or LaSalle nuclear plants to be at risk for premature retirement. Pursuant to this development, in the third quarter of 2021 Exelon and Generation reversed $94 million of the one-time charges initially recorded in 2020 associated with the early retirements and adjusted the expected economic useful life to 2044 and 2046 for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective operating license for each unit.
The Clean Energy Law also contains requirements associated with ComEd’s transition away from the performance-based electric distribution formula rate. The law authorizing that rate setting process sunsets at the end of 2022. The Clean Energy Law, and tariffs adopted under it, governs both the remaining reconciliations of rates set under that process and requires ComEd to file in 2023 its choice of either a general rate case or a four-year multi-year plan to set rates that take effect in 2024. If ComEd elects to file a multi-year plan, that plan would set rates for 2024 – 2027, based on forecasted revenue requirements and an Illinois Commerce Commission determined rate of return on rate base, including the cost of common equity.
•CENG Put Option: On Aug. 6, 2021, Generation and Electricite de France SA (EDF) entered into a settlement agreement pursuant to which Generation, through a wholly owned subsidiary, purchased EDF’s equity interest in Constellation Energy Nuclear Group, LLC (CENG) for a net purchase price of $885 million.
In connection with the settlement agreement, on Aug. 6, 2021, Generation entered into a term loan agreement of approximately of $880 million to fund the transaction, which will expire on Aug. 5, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.875% until March 31, 2022 and a rate of LIBOR plus 1% thereafter and all indebtedness thereunder is unsecured.
•DPL Delaware Electric Distribution Base Rate Case: On Sept. 15, 2021, the DPSC approved an increase in DPL's annual electric distribution base rates of $14 million, reflecting an ROE of 9.6%. Interim rates went into effect on Oct. 6, 2020, subject to refund. Rates associated with the approved order were effective on Sept. 17, 2021.
•DPL Maryland Electric Distribution Base Rate Case: On Sept. 1, 2021, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $29 million, reflecting an ROE of 10.1%. DPL expects a decision in the first quarter of 2022 but cannot predict if the MDPSC will approve the application as filed.
•ACE Conservation Incentive Program (CIP): On April 27, 2021, the New Jersey Board of Public Utilities approved a settlement filed by ACE that included ACE’s ability to implement a CIP prospectively effective July 1, 2021 which would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue for most customers. As a result of this decoupling mechanism, operating revenues will no longer be impacted by abnormal weather or usage for most customers.
•Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100% of the CENG units, produced 44,850 gigawatt-hours (GWhs) in the third quarter of 2021, compared with 44,884 GWhs in the third quarter of 2020. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 96.0% capacity factor for the third quarter of 2021, compared with 96.0% for the third quarter of 2020. The number of planned
4
refueling outage days in the third quarter of 2021 totaled 22, compared with 17 in the third quarter of 2020. There were no non-refueling outage days in the third quarter of 2021 and four in the third quarter of 2020.
•Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 99.4% in the third quarter of 2021, compared with 98.9% in the third quarter of 2020.
Energy Capture for the wind and solar fleet was 95.8% in the third quarter of 2021, compared with 91.9% in the third quarter of 2020.
•Financing Activities:
◦On Aug. 12, 2021, ComEd issued $450 million of its First Mortgage 2.75% Bonds, Series 131, due Sept. 1, 2051. ComEd used the proceeds to repay existing indebtedness and for general corporate purposes.
◦On Sept. 14, 2021, PECO issued $375 million of its First and Refunding Mortgage Bonds, 2.85% Series, due Sept. 15, 2051. PECO used the proceeds to repay existing indebtedness and for general corporate purposes.
◦On Sept. 28, 2021, Pepco issued $125 million of its First Mortgage Bonds 3.29% Series, due Sept. 28, 2051. Pepco used the proceeds to repay existing indebtedness and for general corporate purposes.
Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 do not include the following items (after tax) that were included in reported GAAP Net Income:
(in millions)
Exelon Earnings per Diluted Share
Exelon
ComEd
PECO
BGE
PHI
Generation
2021 GAAP Net Income (Loss)
$
1.23
$
1,203
$
220
$
111
$
36
$
266
$
607
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $192 and $190, respectively)
(0.57)
(559)
—
—
—
—
(565)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $70)
0.06
55
—
—
—
—
55
Asset Impairments (net of taxes of $11)
0.03
33
—
—
—
—
33
Plant Retirements and Divestitures (net of taxes of $71)
0.22
211
—
—
—
—
211
Cost Management Program (net of taxes of $1)
0.01
6
—
1
1
1
3
Change in Environmental Liabilities (net of taxes of $1)
—
4
—
—
—
—
4
COVID-19 Direct Costs (net of taxes of $1, $0, $0, $0, and $1, respectively)
0.01
7
—
1
1
1
4
Asset Retirement Obligation (net of taxes of $12, $1, and $13, respectively)
(0.04)
(35)
—
—
—
2
(37)
Acquisition Related Costs (net of taxes of $2)
0.01
7
—
—
—
—
7
ERP System Implementation Costs (net of taxes of $1)
—
4
—
—
—
—
4
Planned Separation Costs (net of taxes of $10, $2, $1, $1, $1, and $4, respectively)
0.03
27
4
2
2
3
12
Costs Related to Suspension of Contractual Offset (net of taxes of $33)
0.11
107
—
—
—
—
107
Income Tax-Related Adjustments (entire amount represents tax expense)
0.02
19
—
—
—
—
(2)
Noncontrolling Interests (net of taxes of $5)
(0.02)
(17)
—
—
—
—
(17)
2021 Adjusted (non-GAAP) Operating Earnings
$
1.09
$
1,070
$
224
$
114
$
40
$
272
$
427
6
Adjusted (non-GAAP) Operating Earnings for the third quarter of 2020 do not include the following items (after tax) that were included in reported GAAP Net Income:
(in millions)
Exelon Earnings per Diluted Share
Exelon
ComEd
PECO
BGE
PHI
Generation
2020 GAAP Net Income (Loss)
$
0.51
$
501
$
196
$
138
$
53
$
216
$
49
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $62 and $64, respectively)
(0.19)
(183)
—
—
—
—
(192)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $161)
(0.18)
(172)
—
—
—
—
(172)
Asset Impairments (net of taxes of $126)
0.38
375
—
—
—
—
375
Plant Retirements and Divestitures (net of taxes of $111)
0.34
329
—
—
—
—
329
Cost Management Program (net of taxes of $5, $0, $0, $1, and $4, respectively)
0.02
15
—
1
1
1
12
Change in Environmental Liabilities (net of taxes of $6)
0.02
17
—
—
—
—
17
COVID-19 Direct Costs (net of taxes of $3, $1, $0, and $2, respectively)
0.01
10
—
2
—
1
7
Asset Retirement Obligation (net of taxes of $1)
—
3
—
—
—
3
—
Acquisition Related Costs (net of taxes of $1)
—
2
—
—
—
—
2
Income Tax-Related Adjustments (entire amount represents tax expense)
0.06
62
—
—
—
(1)
(28)
Noncontrolling Interests (net of taxes of $12)
0.06
57
—
—
—
—
57
2020 Adjusted (non-GAAP) Operating Earnings
$
1.04
$
1,017
$
197
$
141
$
54
$
220
$
456
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 56.2% and 48.3% for the three months ended Sept. 30, 2021 and 2020, respectively.
7
Webcast Information
Exelon will discuss third quarter 2021 earnings in a conference call scheduled for today at 9 a.m. Central Time (10 a.m. Eastern Time). The webcast and associated materials can be accessed at www.exeloncorp.com/investor-relations.
About Exelon
Exelon Corporation (Nasdaq: EXC) is a Fortune 100 energy company with the largest number of electricity and natural gas customers in the U.S. Exelon does business in 48 states, the District of Columbia, and Canada and had 2020 revenue of $33 billion. Exelon serves approximately 10 million customers in Delaware, the District of Columbia, Illinois, Maryland, New Jersey, and Pennsylvania through its Atlantic City Electric, BGE, ComEd, Delmarva Power, PECO, and Pepco subsidiaries. Exelon is one of the largest competitive U.S. power generators, with more than 31,000 megawatts of nuclear, gas, wind, solar and hydroelectric generating capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 2 million residential, public sector, and business customers, including three fourths of the Fortune 100. Follow Exelon on Twitter @Exelon.
Non-GAAP Financial Measures
In addition to net income as determined under generally accepted accounting principles in the United States (GAAP), Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) Operating Earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) Operating Earnings exclude certain costs, expenses, gains and losses, and other specified items. This measure is intended to enhance an investor’s overall understanding of period over period operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this measure is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) Operating Earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentation. The Company has provided the non-GAAP financial measure as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. Adjusted (non-GAAP) Operating Earnings should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP Net Income measures provided in this earnings release and attachments. This press release and earnings release attachments provide reconciliations of Adjusted (non-GAAP) Operating Earnings to the most directly comparable financial measures calculated and presented in accordance with GAAP, are posted on Exelon’s website: www.exeloncorp.com, and have been furnished to the Securities and Exchange Commission on Form 8-K on Nov. 3, 2021.
Cautionary Statements Regarding Forward-Looking Information
This press release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature, and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future
8
events and operational, economic, and financial performance, are intended to identify such forward-looking statements.
The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants' 2020 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) the Registrants' Third Quarter 2021 Quarterly Report on Form 10-Q (to be filed on Nov. 3, 2021) in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 15, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.
Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, which apply only as of the date of this press release. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.
Equity in (losses) earnings of unconsolidated affiliates
—
—
—
—
(6)
1
(5)
Net income (loss)
609
383
290
535
(122)
(254)
1,441
Net income attributable to noncontrolling interests
—
—
—
—
125
1
126
Net income (loss) attributable to common shareholders
$
609
$
383
$
290
$
535
$
(247)
$
(255)
$
1,315
Nine Months Ended September 30, 2020
Operating revenues
$
4,499
$
2,306
$
2,284
$
3,554
$
13,272
$
(990)
$
24,925
Operating expenses
Purchased power and fuel
1,557
768
731
1,316
6,961
(927)
10,406
Operating and maintenance
1,173
742
567
813
4,188
(113)
7,370
Depreciation and amortization
841
259
405
585
1,161
61
3,312
Taxes other than income taxes
227
131
200
343
364
34
1,299
Total operating expenses
3,798
1,900
1,903
3,057
12,674
(945)
22,387
Gain on sales of assets and businesses
—
—
—
2
12
2
16
Operating income (loss)
701
406
381
499
610
(43)
2,554
Other income and (deductions)
Interest expense, net
(287)
(108)
(99)
(201)
(277)
(269)
(1,241)
Other, net
32
12
17
42
199
50
352
Total other income and (deductions)
(255)
(96)
(82)
(159)
(78)
(219)
(889)
Income (loss) before income taxes
446
310
299
340
532
(262)
1,665
Income taxes
142
(7)
26
(77)
41
16
141
Equity in earnings (losses) of unconsolidated affiliates
—
—
—
1
(6)
—
(5)
Net income (loss)
304
317
273
418
485
(278)
1,519
Net loss attributable to noncontrolling interests
—
—
—
—
(85)
—
(85)
Net income (loss) attributable to common shareholders
$
304
$
317
$
273
$
418
$
570
$
(278)
$
1,604
Change in Net income from 2020 to 2021
$
305
$
66
$
17
$
117
$
(817)
$
23
$
(289)
__________
(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 56.2% and 48.3% for the three months ended September 30, 2021 and 2020, respectively.
(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)For ComEd, BGE, Pepco, DPL Maryland, and ACE customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes.
(c)For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, PECO, BGE, and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).
(1)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.
(2)In 2020, primarily reflects an impairment in the New England asset group. In 2021, reflects an impairment of a wind project at Generation.
(3)In 2020, primarily reflects one-time charges and accelerated depreciation and amortization expenses associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decisions to early retire Byron and Dresden, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates.
(4)Primarily represents reorganization and severance costs related to cost management programs.
(5)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(6)Reflects costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG, which was completed in the third quarter of 2021.
(7)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(8)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.
(9)For Generation, reflects an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021.
(10)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(11)Represents costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(12)Decommissioning-related activities for the former ComEd and PECO units (Regulatory Agreement Units), net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s consolidated statements of operations. These costs reflect the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.
(13)For ComEd, reflects increased electric distribution, transmission, and energy efficiency revenues (due to higher rate base, higher electric distribution ROE due to increased treasury rates, and higher fully recoverable costs). For PHI, reflects increased revenue primarily due to distribution rate increases and increased transmission revenues.
(14)Primarily reflects a decrease in fuel prices.
(15)Reflects decreased capacity revenues in the Mid-Atlantic, Midwest, and Other Power Regions, partially offset by increased revenues in New York.
(16)Primarily reflects an increase in New York ZEC revenues due to higher generation and an increase in ZEC prices and higher gas revenues, net of fuel costs, due to higher natural gas prices.
(17)Primarily reflects an increase in the number of nuclear outage days in 2021, excluding Salem.
(18)Reflects ongoing capital expenditures across all utilities.
(19)For PECO, primarily reflects a decrease in the tax repairs deduction. For BGE, primarily reflects the multi-year plan which resulted in the acceleration of certain income tax benefits. For PHI, primarily due to a distribution rate case settlement which allows PHI to retain certain tax benefits. For Generation and Corporate, primarily reflects the reversal of part of the tax expense recorded in the first quarter, due to the loss before income taxes at Generation due to the February 2021 extreme cold weather event.
(20)Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021.
(21)For Generation, primarily reflects net unrealized and realized losses on equity investments, partially offset by higher realized NDT fund gains.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 42.4% and 134.1% for the nine months ended September 30, 2021 and 2020, respectively.
(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)For ComEd, BGE, Pepco, DPL Maryland, and ACE customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes.
(c)For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, PECO, BGE, and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).
(1)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.
(2)In 2020, reflects an impairment at ComEd related to the acquisition of transmission assets and an impairment in the New England asset group in the third quarter of 2020. In 2021, reflects an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project at Generation.
(3)In 2020, primarily reflects one-time charges and accelerated depreciation and amortization expenses associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decisions to early retire Byron, Dresden, and Mystic Units 8 and 9, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021 and a gain on sale of Generation's solar business. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates.
(4)Primarily represents reorganization and severance costs related to cost management programs.
(5)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(6)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered in July 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.
(7)Reflects costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG, which was completed in the third quarter of 2021.
(8)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(9)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.
(10)For Generation, reflects an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021.
(11)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(12)Represents costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(13)Decommissioning-related activities for the former ComEd and PECO units (Regulatory Agreement Units), net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s consolidated statements of operations. These costs reflect the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.
(14)For ComEd, reflects increased electric distribution, transmission, and energy efficiency revenues (due to higher rate base, higher electric distribution ROE due to increased treasury rates, and higher fully recoverable costs). For BGE and PHI, primarily reflects an increase in revenue as a result of the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities. For BGE, also reflects increased distribution revenue due to customer growth. For PHI, also reflects increased revenue primarily due to distribution and transmission rate increases.
(15)Primarily reflects a decrease in nuclear outage days at Salem.
(16)Primarily reflects a decrease in fuel prices.
(17)Reflects decreased capacity revenues in the Midwest and Other Power Regions, partially offset by increased revenues in the Mid-Atlantic and New York.
(18)Primarily reflects the impacts of the February 2021 extreme cold weather event, partially offset by an increase in New York ZEC revenues due to higher generation and an increase in ZEC prices and higher gas revenues, net of fuel costs, due to higher natural gas prices.
(19)Primarily reflects a decrease in the number of nuclear outage days in 2021, excluding Salem.
(20)For PECO, primarily reflects a net decrease in storm costs resulting from the absence of the June and August 2020 storms, partially offset by storm costs in 2021. For PHI, primarily reflects the absence of costs in 2021 due to the August 2020 storms. For Generation, reflects increased credit loss expense primarily due to the impacts of the February 2021 extreme cold weather event, partially offset by a decrease in planned nuclear outage days at Salem in 2021.
(21)Reflects ongoing capital expenditures across all utilities. For ComEd, also reflects increased amortization of deferred energy efficiency costs.
(22)For BGE, primarily due to the multi-year plan which resulted in the acceleration of certain income tax benefits, partially offset by the absence of the impacts associated with the prior year settlement agreement of ongoing transmission related income tax regulatory liabilities. For PHI, primarily due to the absence of the impacts associated with the prior year settlement agreement of ongoing transmission related income tax regulatory liabilities, partially offset by the multi-year plan which resulted in the acceleration of certain income tax benefits and a distribution rate case settlement which allows PHI to retain certain tax benefits. For Generation and Corporate, primarily reflects the timing of tax expense driven primarily by the loss before income taxes at Generation due to the February 2021 extreme cold weather event. These timing impacts will continue to reverse by the end of the year. For Generation, also reflects the absence of a prior year one-time tax settlement.
(23)Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021.
(24)For Generation, primarily reflects higher realized NDT fund gains, partially offset by net unrealized and realized losses on equity investments.
Net income attributable to noncontrolling interests
26
23
(o)
68
(57)
(o)
Net income attributable to common shareholders
$
1,203
$
501
Effective tax rate(p)
12.4
%
27.5
%
Earnings per average common share
Basic
$
1.23
$
0.51
Diluted
$
1.23
$
0.51
Average common shares outstanding
Basic
979
976
Diluted
980
977
__________
(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).
(b)Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.
(c)In 2021, adjustment to exclude primarily accelerated depreciation and amortization associated with Generation's decisions to early retire Byron and Dresden, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. In 2020, adjustment to exclude primarily one-time charges and accelerated depreciation and amortization associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024.
(d)Adjustment to exclude primarily reorganization and severance costs related to cost management programs.
(e)In 2021, adjustment to exclude an impairment of a wind project at Generation. In 2020, adjustment to exclude primarily an impairment in the New England asset group.
(f)Adjustment to exclude direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(g)Adjustment to exclude costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG, which was completed in the third quarter of 2021.
(h)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(i)Adjustment to exclude costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(j)Adjustment to exclude changes in environmental liabilities.
(k)Adjustment to exclude the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021, reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.
(l)In 2021, adjustment to exclude an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021. In 2020, adjustment to exclude ARO updates.
(m)Adjustment to exclude the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.
(n)Adjustment to exclude primarily the adjustment to deferred income taxes due to changes in forecasted apportionment.
(o)Adjustment to exclude elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.
(p)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 11.6% and 15.0% for the three months ended September 30, 2021 and 2020, respectively.
Net income (loss) attributable to noncontrolling interests
126
(10)
(o)
(85)
(15)
(o)
Net income attributable to common shareholders
$
1,315
$
1,604
Effective tax rate(q)
13.7
%
8.5
%
Earnings per average common share
Basic
$
1.34
$
1.64
Diluted
$
1.34
$
1.64
Average common shares outstanding
Basic
978
976
Diluted
979
976
__________
(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).
(b)Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.
(c)In 2021, adjustment to exclude primarily accelerated depreciation and amortization associated with Generation's decisions to early retire Byron, Dresden, and Mystic Units 8 and 9, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021 and a gain on sale of Generation's solar business. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. In 2020, adjustment to exclude primarily one-time charges and accelerated depreciation and amortization associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024.
(d)Adjustment to exclude primarily reorganization and severance costs related to cost management programs.
(e)In 2021, adjustment to exclude an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project at Generation. In 2020, adjustment to exclude an impairment at ComEd related to the acquisition of transmission assets and an impairment in the New England asset group in the third quarter of 2020.
(f)Adjustment to exclude direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(g)Adjustment to exclude costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG, which was completed in the third quarter of 2021.
(h)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(i)Adjustment to exclude costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(j)Adjustment to exclude changes in environmental liabilities.
(k)Adjustment to exclude the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021, reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.
(l)In 2021, adjustment to exclude an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021. In 2020, adjustment to exclude ARO updates.
(m)Adjustment to exclude the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.
(n)Adjustment to exclude primarily the adjustment to deferred income taxes due to changes in forecasted apportionment.
(o)Adjustment to exclude elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.
(p)Adjustment to exclude the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered in July 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.
(q)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 15.4% and 9.0% for the nine months ended September 30, 2021 and 2020, respectively.
(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).
(b)Adjustment to exclude an impairment related to the acquisition of transmission assets.
(c)Adjustment to exclude the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered in July 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.
(d)Represents costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).
(b)Adjustment to exclude direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(c)Represents costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(d)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(e)Adjustment to exclude reorganization costs related to cost management programs.
(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).
(b)Adjustment to exclude direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(c)Adjustment to exclude costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(d)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(e)Adjustment to exclude reorganization costs related to cost management programs.
(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).
(b)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(c)Adjustment to exclude costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(d)Adjustment to exclude reorganization and severance costs related to cost management programs.
(e)Adjustment to exclude direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(f)Adjustment to exclude an ARO update.
(g)Adjustment to exclude deferred income taxes due to changes in forecasted appointment.
(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).
(b)Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.
(c)In 2021, adjustment to exclude primarily accelerated depreciation and amortization associated with Generation's decisions to early retire Byron, Dresden, and Mystic Units 8 and 9, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021 and a gain on sale of Generation's solar business. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. In 2020, adjustment to exclude primarily one-time charges and accelerated depreciation and amortization associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024.
(d)Adjustment to exclude primarily reorganization and severance costs related to cost management programs.
(e)In 2021, adjustment to exclude an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project at Generation. In 2020, adjustment to exclude primarily an impairment in the New England asset group in the third quarter of 2020.
(f)Adjustment to exclude direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(g)Adjustment to exclude costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG, which was completed in the third quarter of 2021.
(h)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(i)Adjustment to exclude costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(j)Adjustment to exclude changes in environmental liabilities.
(k)Adjustment to exclude the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.
(l)In 2021, adjustment to exclude an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021.
(m)Adjustment to exclude the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.
(n)Adjustment to exclude primarily the adjustment to deferred income taxes due to changes in forecasted apportionment.
(o)Adjustment to exclude elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.
Net income attributable to noncontrolling interests
—
—
Net loss attributable to common shareholders
$
(37)
$
(151)
Nine Months Ended September 30, 2021
Nine Months Ended September 30, 2020
GAAP (b)
Non-GAAP Adjustments
GAAP (b)
Non-GAAP Adjustments
Operating revenues
$
(921)
$
—
$
(990)
$
—
Operating expenses
Purchased power and fuel
(868)
—
(927)
—
Operating and maintenance
(57)
(11)
(c)
(113)
3
(f)
Depreciation and amortization
53
—
61
—
Taxes other than income taxes
37
—
34
—
Total operating expenses
(835)
(945)
Gain on sales of assets and businesses
3
—
2
—
Operating loss
(83)
(43)
Other income and (deductions)
Interest expense, net
(240)
—
(269)
38
(d),(e)
Other, net
60
6
(d)
50
—
Total other income and (deductions)
(180)
(219)
Loss before income taxes
(263)
(262)
Income taxes
(8)
(17)
(c),(d),(e)
16
(78)
(d),(e),(f)
Equity in earnings of unconsolidated affiliates
1
—
—
—
Net loss
(254)
(278)
Net income attributable to noncontrolling interests
1
—
Net loss attributable to common shareholders
$
(255)
$
(278)
__________
(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 accounting principles generally accepted in the United States (GAAP).
(c)Adjustment to exclude costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
(d)Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.
(e)Adjustment to exclude primarily the adjustment to deferred income taxes due to changes in forecasted apportionment.
(f)Adjustment to exclude reorganization costs related to cost management programs.
(a)Reflects revenues 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, revenues also reflect the cost of energy and transmission.
(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(c)Includes operating revenues from affiliates totaling $9 million and $15 million for the three months ended September 30, 2021 and 2020, respectively, and $19 million and $31 million for the nine months ended September 30, 2021 and 2020, respectively.
(d)Includes alternative revenue programs and late payment charges.
Rate-Regulated Electric Deliveries and Revenues(a)
Residential
11,201
10,874
3.0
%
1.0
%
$
1,325
$
1,277
3.8
%
Small commercial & industrial
5,796
5,493
5.5
%
3.9
%
312
291
7.2
%
Large commercial & industrial
10,627
10,393
2.3
%
1.8
%
183
174
5.2
%
Public authorities & electric railroads
425
407
4.4
%
4.3
%
24
21
14.3
%
Other(b)
—
—
n/a
n/a
167
171
(2.3)
%
Total rate-regulated electric revenues(c)
28,049
27,167
3.2
%
2.0
%
2,011
1,934
4.0
%
Other Rate-Regulated Revenues(d)
22
14
57.1
%
Total Electric Revenues
2,033
1,948
4.4
%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential
27,945
25,867
8.0
%
0.8
%
251
252
(0.4)
%
Small commercial & industrial
15,217
13,020
16.9
%
7.5
%
94
86
9.3
%
Large commercial & industrial
13
20
(35.0)
%
7.7
%
—
—
N/A
Transportation
18,474
17,553
5.2
%
4.0
%
17
18
(5.6)
%
Other(f)
—
—
n/a
n/a
4
3
33.3
%
Total rate-regulated natural gas revenues(g)
61,649
56,460
9.2
%
3.3
%
366
359
1.9
%
Other Rate-Regulated Revenues(d)
—
(1)
100.0
%
Total Natural Gas Revenues
366
358
2.2
%
Total Electric and Natural Gas Revenues
$
2,399
$
2,306
4.0
%
Purchased Power and Fuel
$
800
$
768
4.2
%
% Change
Heating and Cooling Degree-Days
2021
2020
Normal
From 2020
From Normal
Heating Degree-Days
2,710
2,594
2,865
4.5
%
(5.4)
%
Cooling Degree-Days
1,517
1,504
1,402
0.9
%
8.2
%
Number of Electric Customers
2021
2020
Number of Natural Gas Customers
2021
2020
Residential
1,514,836
1,505,080
Residential
495,752
490,158
Small commercial & industrial
155,006
154,183
Small commercial & industrial
44,435
44,138
Large commercial & industrial
3,108
3,105
Large commercial & industrial
6
5
Public authorities & electric railroads
10,271
10,149
Transportation
670
715
Total
1,683,221
1,672,517
Total
540,863
535,016
__________
(a)Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenues also reflect the cost of energy and transmission.
(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(c)Includes operating revenues from affiliates totaling $2 million and $3 million for the three months ended September 30, 2021 and 2020, and $5 million and $6 million for the nine months ended September 30, 2021 and 2020 respectively.
(d)Includes alternative revenue programs and late payment charges.
(e)Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.
(f)Includes revenues primarily from off-system sales.
(g)Includes operating revenues from affiliates totaling less than $1 million for both the three months ended September 30, 2021 and 2020, and $1 million for both the nine months ended September 30, 2021 and 2020, respectively.
Rate-Regulated Electric Deliveries and Revenues(a)
Residential
10,046
9,807
2.4
%
(0.2)
%
$
1,044
$
1,034
1.0
%
Small commercial & industrial
2,128
2,035
4.6
%
2.1 %
202
183
10.4
%
Large commercial & industrial
10,054
9,657
4.1
%
2.0 %
342
311
10.0
%
Public authorities & electric railroads
149
157
(5.1)
%
(4.8)
%
20
20
—
%
Other(b)
—
—
n/a
n/a
269
233
15.5
%
Total rate-regulated electric revenues(c)
22,377
21,656
3.3
%
1.0 %
1,877
1,781
5.4
%
Other Rate-Regulated Revenues(d)
(11)
(18)
(38.9)
%
Total Electric Revenues
1,866
1,763
5.8
%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential
25,758
26,394
(2.4)
%
(11.3)
%
354
342
3.5
%
Small commercial & industrial
6,226
6,241
(0.2)
%
(7.5)
%
59
55
7.3
%
Large commercial & industrial
29,559
28,236
4.7
%
1.4 %
103
96
7.3
%
Other(f)
9,125
5,095
79.1
%
n/a
41
16
156.3
%
Total rate-regulated natural gas revenues(g)
70,668
65,966
7.1
%
(5.4)
%
557
509
9.4
%
Other Rate-Regulated Revenues(d)
3
12
(75.0)
%
Total Natural Gas Revenues
560
521
7.5
%
Total Electric and Natural Gas Revenues
$
2,426
$
2,284
6.2
%
Purchased Power and Fuel
$
840
$
731
14.9
%
% Change
Heating Degree-Days
2021
2020
Normal
From 2020
From Normal
Heating Degree-Days
2,708
2,499
2,956
8.4
%
(8.4)
%
Cooling Degree-Days
1,039
998
867
4.1
%
19.8
%
Number of Electric Customers
2021
2020
Number of Natural Gas Customers
2021
2020
Residential
1,194,254
1,187,498
Residential
649,745
644,872
Small commercial & industrial
114,814
114,038
Small commercial & industrial
38,216
38,173
Large commercial & industrial
12,584
12,428
Large commercial & industrial
6,167
6,083
Public authorities & electric railroads
268
267
Total
694,128
689,128
Total
1,321,920
1,314,231
__________
(a)Reflects revenues from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenues also reflect the cost of energy and transmission.
(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(c)Includes operating revenues from affiliates totaling $4 million and $3 million for the three months ended September 30, 2021 and 2020, respectively, and $10 million and $9 million for the nine months ended September 30, 2021 and 2020, respectively.
(d)Includes alternative revenue programs and late payment charges.
(e)Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.
(f)Includes revenues primarily from off-system sales.
(g)Includes operating revenues from affiliates totaling $3 million for both the three months ended September 30, 2021 and 2020, and $10 million and $7 million for the nine months ended September 30, 2021 and 2020, respectively.
(a)Reflects revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenues also reflect the cost of energy and transmission.
(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(c)Includes operating revenues from affiliates totaling $2 million and $3 million for the three months ended September 30, 2021 and 2020, respectively, and $4 million and $6 million for the nine months ended September 30, 2021 and 2020, respectively.
(d)Includes alternative revenue programs and late payment charge revenues.
Rate-Regulated Electric Deliveries and Revenues(a)
Residential
4,245
4,088
3.8
%
1.5
%
$
535
$
501
6.8
%
Small commercial & industrial
1,787
1,581
13.0
%
11.9
%
145
127
14.2
%
Large commercial & industrial
3,145
3,185
(1.3)
%
(1.7)
%
70
66
6.1
%
Public authorities & electric railroads
34
32
6.3
%
8.5
%
11
10
10.0
%
Other(b)
—
—
n/a
n/a
143
148
(3.4)
%
Total rate-regulated electric revenues(c)
9,211
8,886
3.7
%
2.3
%
904
852
6.1
%
Other Rate-Regulated Revenues(d)
18
(14)
(228.6)
%
Total Electric Revenues
922
838
10.0
%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential
5,507
5,256
4.8
%
(1.2)
%
67
68
(1.5)
%
Small commercial & industrial
2,647
2,567
3.1
%
(2.2)
%
29
30
(3.3)
%
Large commercial & industrial
1,247
1,265
(1.4)
%
(1.6)
%
5
3
66.7
%
Transportation
4,997
4,811
3.9
%
2.3
%
11
10
10.0
%
Other(f)
—
—
n/a
n/a
6
5
20.0
%
Total rate-regulated natural gas revenues
14,398
13,899
3.6
%
(0.3)
%
118
116
1.7
%
Other Rate-Regulated Revenues(d)
—
—
n/a
Total Natural Gas Revenues
118
116
1.7
%
Total Electric and Natural Gas Revenues
$
1,040
$
954
9.0
%
Purchased Power and Fuel
$
402
$
379
6.1
%
Electric Service Territory
% Change
Heating and Cooling Degree-Days
2021
2020
Normal
From 2020
From Normal
Heating Degree-Days
2,739
2,551
2,904
7.4
%
(5.7)
%
Cooling Degree-Days
1,376
1,332
1,239
3.3
%
11.1
%
Natural Gas Service Territory
% Change
Heating Degree-Days
2021
2020
Normal
From 2020
From Normal
Heating Degree-Days
2,848
2,664
3,025
6.9
%
(5.9)
%
Number of Electric Customers
2021
2020
Number of Natural Gas Customers
2021
2020
Residential
476,008
471,875
Residential
127,740
126,659
Small commercial & industrial
62,990
62,291
Small commercial & industrial
9,935
9,885
Large commercial & industrial
1,215
1,234
Large commercial & industrial
21
17
Public authorities & electric railroads
605
610
Transportation
158
160
Total
540,818
536,010
Total
137,854
136,721
__________
(a)Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenues also reflect the cost of energy and transmission.
(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(c)Includes operating revenues from affiliates totaling $2 million and $3 million for the three months ended September 30, 2021 and 2020, respectively, and $6 million and $7 million for the nine months ended September 30, 2021 and 2020, respectively.
(d)Includes alternative revenue programs and late payment charges.
(e)Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.
(f)Includes revenues primarily from off-system sales.
(a)Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenues also reflect the cost of energy and transmission.
(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.
(c)Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2021 and 2020, and $2 million and $3 million for the nine months ended September 30, 2021 and 2020, respectively.
(a)Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants. Includes the total output for fully owned plants and the total output for CENG prior to the acquisition of EDF’s interest on August 6, 2021 as CENG was fully consolidated.
(b)Other Power Regions includes New England, South, West, and Canada.
(c)Includes affiliate sales to PECO, BGE, Pepco, DPL, and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
