EXELON CORPORATION 
Exelon
Executive Overview Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. Exelon has eleven reportable segments consisting of Generation's five reportable segments (Mid-Atlantic, Midwest,New York ,ERCOT , and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 - Significant Accounting Policies and Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments. Exelon's consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management's Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 , and is separately filed byExelon, Generation , ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 , refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2019 Form 10-K, which was filed with theSEC onFebruary 11, 2020 . COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus. The Registrants have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on their employees. In addition, the Registrants have updated existing business continuity plans in the context of this pandemic. The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers. There were no changes in internal control over financial reporting in 2020 as a result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information. Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas at Generation and the Utility Registrants, which has resulted in a decrease in operating revenues. As a result of COVID-19, Generation temporarily suspended interruption of service for all retail residential customers for non-payment and temporarily ceased new late payment fees for all retail customers from March to May of 2020. Starting in March of 2020, the Utility Registrants also temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on such measures at the Utility Registrants. At Generation, such measures resulted in an increase in credit loss expense. ComEd and ACE recorded regulatory assets for the incremental credit loss expense based on existing mechanisms. BGE, PECO, Pepco, and DPL also recorded regulatory assets for substantially all the incremental credit loss expense incurred in 2020. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 58
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Generation and the Utility Registrants have also incurred 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 their employees. At Generation and PECO, such costs are recorded as Operating and maintenance expense and are excluded from Adjusted (non-GAAP) Operating Earnings. At ComEd, BGE, Pepco, DPL, and ACE, such costs are primarily recorded as regulatory assets. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. The estimated impact to Generation's and the Utility Registrants' Net income is approximately$170 million and$75 million for the year endedDecember 31, 2020 , respectively. To offset the unfavorable impacts from COVID-19, the Registrants identified approximately$250 million in cost savings across Generation and the Utility Registrants in 2020. The cost savings achieved in 2020 were higher than originally anticipated. The Registrants rely on the capital markets for publicly offered debt as well as the commercial paper markets to meet their financial commitments and short-term liquidity needs. As a result of the disruptions in the commercial paper markets in March of 2020, Generation borrowed$1.5 billion on its revolving credit facility to refinance commercial paper, which Generation repaid onApril 3, 2020 . Generation also entered into two short-term loan agreements in March of 2020 for an aggregate of$500 million . OnApril 8, 2020 , Generation received approximately$500 million in cash after entering into an accounts receivable financing arrangement. OnApril 24, 2020 , Exelon Corporate entered into a credit agreement establishing a$550 million 364-day revolving credit facility to be used as an additional source of short-term liquidity. In addition, the Registrants issued long-term debt of$5.3 billion and were able to successfully complete their planned long-term debt issuances in 2020. See Liquidity and Capital Resources, Note 17 - Debt and Credit Agreements, and Note 6 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 as a result of COVID-19. See Note 12 - Asset Impairments for additional information related to other impairment assessments in the third quarter of 2020. Certain assumptions are highly sensitive to changes. Changes in significant assumptions could potentially result in future impairments, which could be material. This is an evolving situation that could lead to extended disruption of economic activity in our markets. The Registrants will continue to monitor developments affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts. The extent to which COVID-19 may impact the Registrants' ability to operate their generating and transmission and distribution assets, the ability to access capital markets, and results of operations, including demand for electricity and natural gas, will depend on the spread and proliferation of COVID-19 around the world and future developments, which are highly uncertain and cannot be predicted at this time. 59
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Financial Results of Operations GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the year endedDecember 31, 2020 compared to the same period in 2019. For additional information regarding the financial results for the years endedDecember 31, 2020 and 2019 see the discussions of Results of Operations by Registrant. 2020 2019 (Unfavorable) Favorable Variance Exelon$ 1,963 $ 2,936 $ (973) Generation 589 1,125 (536) ComEd 438 688 (250) PECO 447 528 (81) BGE 349 360 (11) PHI 495 477 18 Pepco 266 243 23 DPL 125 147 (22) ACE 112 99 13 Other(a) (355) (242) (113) __________ (a)Primarily includes eliminating and consolidating adjustments, Exelon's corporate operations, shared service entities, and other financing and investing activities. Year EndedDecember 31, 2020 Compared to Year EndedDecember 31, 2019 . Net income attributable to common shareholders decreased by$973 million and diluted earnings per average common share decreased to$2.01 in 2020 from$3.01 in 2019 primarily due to: •One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retireByron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of accelerated depreciation and amortization due to the early retirement of TMI inSeptember 2019 ; •Impairment of theNew England asset group; •Payments that ComEd made under the Deferred Prosecution Agreement. See Note 19 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information;
•Lower capacity revenue;
•Reduction in load due to COVID-19 at Generation;
•Lower realized energy prices;
•Higher nuclear outage days;
•Impact of Generation's annual update to the nuclear ARO for Non-Regulatory
Agreement Units;
•Lower net unrealized and realized gains on NDT funds;
•COVID-19 direct costs;
•Lower electric distribution earnings from lower allowed ROE due to a decrease
in treasury rates, partially offset by higher rate base at ComEd;
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•Higher storm costs related to the
•Unfavorable weather conditions at PECO, DPL Delaware, and ACE; and
•A net increase in depreciation and amortization expense due to ongoing capital expenditures at PECO, BGE, Pepco, DPL, and ACE, partially offset at Generation due to the impact of extending the operating license atPeach Bottom . The decreases were partially offset by; •Higher mark-to-market gains; •Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter and were fair valued based on quoted market prices of the stocks as ofDecember 31, 2020 ; •Lower operating and maintenance expense at Generation primarily due to previous cost management programs, lower contracting costs, and lower travel costs, partially offset by lower NEIL insurance distributions; •Lower nuclear fuel costs; •A tax benefit related to a settlement in the first quarter of 2020, partially offset by the absence of a tax benefit related to certain research and development activities recorded in the fourth quarter of 2019 at Generation; and •Regulatory rate increases at BGE, DPL, and ACE. Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor's overall understanding of year-to-year operating results and provide an indication of Exelon's baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. 61
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The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year endedDecember 31, 2020 as compared to 2019:
For the Years Ended
2020 2019
Earnings per Earnings per
(All amounts in millions after tax) Diluted Share Diluted Share
Net Income Attributable to Common Shareholders
$ 2.01
(213) (0.22) 197 0.20
Unrealized (Gains) Losses Related to NDT Fund
Investments (net of taxes of $278 and $269 ,
respectively)(a) (256) (0.26) (299) (0.31)
Asset Impairments (net of taxes of $135 and $56 ,
respectively)(b) 396 0.41 123 0.13
Plant Retirements and Divestitures (net of taxes of
718 0.74 118 0.12
Cost Management Program (net of taxes of
45 0.05 51 0.05
Litigation Settlement Gain (net of taxes of $7 ) - - (19) (0.02)
Asset Retirement Obligation (net of taxes of
48 0.05 (84) (0.09)
Change in Environmental Liabilities (net of taxes of
18 0.02 20 0.02
COVID-19 Direct Costs (net of taxes of $19 )(f) 50 0.05 - -
Deferred Prosecution Agreement Payments (net of taxes
of
200 0.20 - -
Acquisition Related Costs (net of taxes of $1 )(h) 4 - - -
ERP System Implementation Costs (net of taxes of
$1 )(i) 3 - - -
Income Tax-Related Adjustments (entire amount
represents tax expense)(j) 71 0.07 5 0.01
Noncontrolling Interests (net of taxes of
103 0.11 90 0.09
Adjusted (non-GAAP) Operating Earnings $ 3,149 $ 3.22 $ 3,139 $ 3.22
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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 funds, the marginal statutory income tax rates for 2020
and 2019 ranged from 26.0% 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 funds were 52.1% and 47.3% for the years ended December 31, 2020
and 2019, respectively.
(a)Reflects the impact of net unrealized gains and losses on Generation's NDT
fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts
of the Regulatory Agreement Units, including the associated income taxes, are
contractually eliminated, resulting in no earnings impact.
(b)In 2020, reflects an impairment at ComEd in the second quarter of 2020
related to the acquisition of transmission assets and an impairment of the New
England asset group in the third quarter of 2020. In 2019, primarily reflects
the impairment of equity method investments in certain distributed energy
companies. The impact of such impairment net of noncontrolling interest is
$0.02 .
(c)In 2020, primarily reflects 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. In 2019, primarily reflects accelerated depreciation and
amortization expenses associated with the early retirement of the TMI nuclear
facility and certain fossil sites and the loss on the sale of Oyster Creek to
Holtec , partially offset by net realized gains related to Oyster Creek's NDT
fund investments, a net benefit associated with remeasurements of the TMI ARO,
and a gain on the sale of certain wind assets.
(d)Primarily represents reorganization and severance costs related to cost
management programs.
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(e)Reflects an adjustment to Generation's nuclear ARO for Non-Regulatory Agreement Units resulting from the annual update. (f)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. (g)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered into onJuly 17, 2020 with theU.S. Attorney's Office for the Northern District of Illinois . (h)Reflects costs related to the acquisition of EDF's interest in CENG. (i)Reflects costs related to a multi-year ERP system implementation. (j)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment. (k)Represents elimination from Generation's results of the noncontrolling interests related to certain exclusion items. In 2020, primarily related to unrealized gains and losses on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies. Significant 2020 Transactions and Developments Planned Separation OnFebruary 21, 2021 , Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 - Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information. Impacts ofFebruary 2021 Weather Events andTexas -based Generating Assets Outages Beginning onFebruary 15, 2021 , Generation'sTexas -based generating assets within theERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased demand for service, limited the availability of natural gas to fuel power plants, and dramatically increased wholesale power and gas prices. Exelon and Generation estimate the impact to their Net income for the first quarter of 2021 arising from these market and weather conditions to be approximately$560 million to$710 million . The estimated impact includes favorable results in certain regions within Generation's wholesale gas business. The ultimate impact to Exelon's and Generation's consolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation and contract disputes which may result. Exelon expects to offset between$410 million and$490 million of this impact primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings. See Note 26 - Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information. Agreement for Sale of Generation's Solar Business OnDecember 8, 2020 , Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation's solar business, including 360 megawatts of generation in operation or under construction across more than 600 sites acrossthe United States , for a purchase price of$810 million . Completion of the transaction is expected to occur in the first half of 2021. Generation will retain certain solar assets not included in this agreement, primarilyAntelope Valley . See Note 2 - Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. 63
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Early Retirement of Generation Facilities InAugust 2020 , Generation announced that it intends to retire theByron Generating Station inSeptember 2021 ,Dresden Generating Station inNovember 2021 , and Mystic Units 8 and 9 at the expiration of the cost of service commitment inMay 2024 . As a result, in the third quarter of 2020, Exelon and Generation recognized a$500 million impairment of itsNew England asset group and one-time non-cash charges forByron , Dresden, and Mystic related to materials and supplies inventory reserve adjustments, employee-related costs, and construction work-in-progress impairments, among other items. In addition, there will be ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel. Such ongoing charges are excluded from Adjusted (non-GAAP) Operating Earnings. The following table summarizes the incremental expense recorded for the year endedDecember 31, 2020 and the estimated amounts of incremental expense expected to be incurred through the retirement dates. Actual
Projected(a)
Income statement expense (pre-tax) 2020 2021 2022 2023 2024 Depreciation and amortization Accelerated depreciation(b)$ 921 $ 2,070 $ 110
Accelerated nuclear fuel amortization 60 170 -
- -
Operating and maintenance
One-time charges 277 30 10 - 20
Other charges(c) 35 10 10 10 5
Contractual offset(d) (364) (475) - - -
Total $ 929 $ 1,805 $ 130 $ 130 $ 75
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(a)Actual results may differ based on incremental future capital additions,
actual units of production for nuclear fuel amortization, future revised ARO
assumptions, etc.
(b)Reflects incremental accelerated depreciation of plant assets, including any
ARC.
(c)Reflects primarily the net impacts associated with the remeasurement of the
ARO for Dresden. See Note 10 - Asset Retirement Obligations of the Combined
Notes to Consolidated Financial Statements for additional information.
(d)Reflects contractual offset for ARO accretion, ARC depreciation, and net
impacts associated with the remeasurement of the ARO for Byron and Dresden.
Based on the regulatory agreement with the ICC, decommissioning-related
activities are offset within Exelon's and Generation's Consolidated Statements
of Operations and Comprehensive Income as long as the net cumulative
decommissioning-related activities result in a regulatory liability at ComEd.
Recognition of a regulatory asset for nuclear decommissioning-related activities
at ComEd is not permissible. The offset results in an equal adjustment to the
noncurrent payables to ComEd at Generation and an adjustment to the regulatory
liabilities at ComEd. See Note 10 - Asset Retirement Obligations of the Combined
Notes to Consolidated Financial Statements for additional information.
Deferred Prosecution Agreement
On July 17, 2020 , ComEd entered into a Deferred Prosecution Agreement (DPA) with
the U.S. Attorney's Office for the Northern District of Illinois (USAO) to
resolve the USAO's investigation into ComEd's lobbying activities in the State
of Illinois . Under the DPA, the USAO filed a single charge alleging that ComEd
improperly gave and offered to give jobs, vendor subcontracts, and payments
associated with those jobs and subcontracts for the benefit of the Speaker of
the Illinois House of Representatives and the Speaker's associates, with the
intent to influence the Speaker's action regarding legislation affecting ComEd's
interests. The DPA provides that the USAO will defer any prosecution of such
charge and any other criminal or civil case against ComEd in connection with the
matters identified therein for a three-year period subject to certain
obligations of ComEd, including payment to the United States Treasury of $200
million , with $100 million payable within thirty days of the filing of the DPA
with the United States District Court for the Northern District of Illinois and
an additional $100 million within ninety days of such filing date. The payments
will not be recovered in rates or charged to customers, and ComEd will not seek
or accept reimbursement or indemnification from any source other than Exelon.
See Note 19 - Commitments and Contingencies for additional information.
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Utility Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions
seeking increases or decreases to their electric transmission and distribution,
and gas distribution rates to recover their costs and earn a fair return on
their investments. The outcomes of these regulatory proceedings impact the
Utility Registrants' current and future financial statements.
The following tables show the Utility Registrants' completed and pending
distribution base rate case proceedings in 2020. See Note 3 - Regulatory Matters
of the Combined Notes to Consolidated Financial Statements for additional
information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Requested Approved
Revenue Revenue
Requirement Requirement
(Decrease) (Decrease)
Registrant/Jurisdiction Filing Date Service Increase Increase Approved ROE Approval Date Rate Effective Date
ComEd - Illinois April 8, 2019 Electric $ (6) $ (17) 8.91 % December 4, 2019 January 1, 2020
ComEd - Illinois April 16, 2020 Electric (11) (14) 8.38 % December 9, 2020 January 1, 2021
May 15, 2020 Electric 137 81 9.50 %
BGE - Maryland (amended September December 16, 2020 January 1, 2021
11, 2020) Natural Gas 91 21 9.65 %
December 5, 2019
DPL - Maryland (amended April 23 , Electric 17 12 9.60 % July 14, 2020 July 16, 2020
2020)
February 21, 2020
DPL - Delaware (amended October 9 , Natural Gas 7 2 9.60 % January 6, 2021 September 21, 2020
2020)
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Pending Distribution Base Rate Case Proceedings
Requested
Revenue
Requirement
Registrant/Jurisdiction Filing Date Service Increase Requested ROE Expected Approval Timing
PECO - Pennsylvania September 30, 2020 Natural Gas $ 69 10.95 % Second quarter of 2021
Pepco - District of Columbia May 30, 2019 (amended Electric 136 9.7 % Second quarter of 2021
June 1, 2020)
Pepco - Maryland October 26, 2020 Electric 110 10.2 % Second quarter of 2021
DPL - Delaware March 6, 2020 (amended Electric 23 10.3 % Third quarter of 2021
February 2, 2021)
ACE - New Jersey December 9, 2020 Electric 67 10.3 % Fourth quarter of 2021
Transmission Formula Rates
The following total increases/(decreases) were included in the Utility
Registrants' 2020 annual electric transmission formula rate updates. See Note 3
- Regulatory Matters of the Combined Notes to Consolidated Financial Statements
for additional information.
Initial Revenue Total Revenue
Requirement Annual Reconciliation Requirement Allowed Return
Registrant Increase/(Decrease) Decrease Increase/(Decrease) on Rate Base Allowed ROE
ComEd $ 18 $ (4) $ 14 8.17 % 11.50 %
PECO 5 (28) (23) 7.47 % 10.35 %
BGE 16 (3) 4 7.26 % 10.50 %
Pepco 2 (46) (44) 7.81 % 10.50 %
DPL (4) (40) (44) 7.20 % 10.50 %
ACE 5 (25) (20) 7.40 % 10.50 %
Sales of Customer Accounts Receivable
On April 8, 2020 , NER, a bankruptcy remote, special purpose entity, which is
wholly owned by Generation, entered into an accounts receivable financing
facility with a number of financial institutions and a commercial paper conduit
to sell certain customer accounts receivables. Generation received approximately
$500 million of cash in accordance with the initial sale of approximately $1.2
billion receivables. See Note 6 - Accounts Receivable of the Combined Notes to
Consolidated Financial Statements for additional information.
Exelon's Strategy and Outlook
On February 21, 2021 , Exelon's Board of Directors approved a plan to separate
the Utility Registrants and Generation, creating two publicly traded companies
with the resources necessary to best serve customers and sustain long-term
investment and operating excellence. The separation gives each company the
financial and strategic independence to focus on its specific customer needs,
while executing its core business strategy. See Note 26 - Subsequent Events of
the Combined Notes to Consolidated Financial Statements for additional
information.
In 2021, the businesses remain focused on maintaining industry leading
operational excellence, meeting or exceeding their financial commitments,
ensuring timely recovery on investments to enable customer benefits, supporting
enactment of clean energy policies, and continued commitment to corporate
responsibility.
Exelon's utility strategy is to improve reliability and operations and enhance
the customer experience, while ensuring ratemaking mechanisms provide the
utilities fair financial returns. The Utility Registrants only invest in rate
base where it provides a benefit to customers and the community by improving
reliability and the service experience or otherwise meeting customer needs. The
Utility Registrants make these investments at the lowest
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reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company. Generation's competitive businesses create value for customers by providing innovative energy solutions and reliable, clean, and affordable energy. Generation's electricity generation strategy is to pursue opportunities that provide stable revenues and match supply to customers. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation's customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets. Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors. Growth Opportunities Management continually evaluates growth opportunities aligned with Exelon's businesses, assets and markets, leveraging Exelon's expertise in those areas and offering sustainable returns. Regulated Energy Businesses. The Utility Registrants anticipate investing approximately$27 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately$15 billion by the end of 2024. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers. Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation's strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that match supply to customers as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development. Other Key Business Drivers and Management Strategies Utility Rates and Rate Proceedings The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants' current and future results of operations, cash flows, and financial positions. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings. Power Markets Price of Fuels The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon's revenues. Forward natural gas prices have declined significantly 67
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over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development). Section 232 Uranium Petition OnJanuary 16, 2018 , two Canadian-owned uranium mining companies with operations in theU.S. jointly submitted a petition to theU.S. Department of Commerce ("DOC") seeking relief under Section 232 of the Trade Expansion Act of 1962 from imports of uranium products, alleging that these imports threaten national security.The United States Nuclear Fuel Working Group ("Working Group") report was made public onApril 23, 2020 .The Working Group report states that nuclear power is intrinsically tied to national security, and promises that theU.S. government will take bold actions to strengthen all parts of the nuclear fuel industry in theU.S. It recommends the Agreement Suspending the Antidumping Investigation on Uranium from theRussian Federation (the "Russian Suspension Agreement" or "RSA") be extended and to consider reducing the amount of Russian imports of nuclear fuel. The Russian Suspension Agreement is the historical resolution of a 1991 DOC investigation that found that the Russians had been selling or "dumping" cheap uranium products into theU.S. The RSA has been amended several times in the intervening years to allowRussia to supply limited amounts of uranium products into theU.S. It was set to expire at the end of 2020, but was amended onOctober 5, 2020 to extend for another 20 years.The Working Group report should be viewed as policy recommendations that may be implemented by executive agencies, congress, and or regulatory bodies. Exelon and Generation cannot currently predict the outcome of all of the policy changes recommended by theWorking Group . Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps OnFebruary 21, 2019 , PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asksFERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation. Energy Demand Load growth at the Utility Registrants is driven by recovery from COVID-19 impacts. ComEd and PECO are projecting modest growth in load of 2.5% and 1.8%, respectively, in 2021 as compared to reduced load in 2020. BGE, Pepco, DPL, and ACE are projecting slower growth as prolonged COVID-19 impacts decrease load by (2.0)%, (0.8)%, (0.9)%, and (2.4)%, respectively, in 2021 compared to 2020.Retail Competition Generation's retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output. Hedging Strategy Exelon's policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As ofDecember 31, 2020 , the percentage of expected generation hedged for the Mid-Atlantic, Midwest,New York , andERCOT reportable segments is 94%-97% for 2021. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk. 68
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Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 60% of Generation's uranium concentrate requirements from 2021 through 2025 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon's and Generation's consolidated financial statements. See Note 16 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers. Other Legislative and Regulatory Developments Illinois Clean Energy Progress Act OnMarch 14, 2019 , the Clean Energy Progress Act was introduced in theIllinois General Assembly to preserveIllinois' clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of PJM's base residual auction process, while utilizing the FRR provisions in PJM's tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of Generation's nuclear plants inIllinois , or from new clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state's competitive retail electricity and natural gas markets, including Generation's retail customers. Energy legislation has also been proposed by other stakeholders in 2019 and 2020, including renewable resource developers, environmental advocates, and coal-fueled generators. Lawmakers focused their efforts on understanding all of the various legislative proposals with the goal of developing a single comprehensive energy package for ultimate consideration by theGeneral Assembly andGovernor Pritzker . Due to the COVID-19 pandemic, the legislative calendar during 2020 was severely curtailed stalling progress on comprehensive energy legislation. The fall 2020 veto session was cancelled. The next opportunity for theGeneral Assembly to consider development of comprehensive energy legislation appears to come during the 2021 spring legislative session. Exelon and Generation will work with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation. Nuclear Powers Act of 2019 OnApril 12, 2019 , the Nuclear Powers America Act of 2019 was introduced to theUnited States Congress , which expands the current investment tax credit to existing nuclear power plants. The proposed legislation would provide a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be currently operational and must have applied for an operating license renewal before 2026. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application, or incorporate estimates and assumptions that are inherently 69
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uncertain and that may change in subsequent periods. Additional information of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements. Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation) Generation's ARO associated with decommissioning its nuclear units was$11.9 billion atDecember 31, 2020 . The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios. As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The availability of NDT funds could impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to Generation's current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios. The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions: Decommissioning Cost Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation's nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle. Cost Escalation Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal, and other costs. All of the nuclear AROs are adjusted each year for the updated cost escalation factors. Probabilistic Cash Flow Models. Generation's probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The assumed decommissioning scenarios include the following three alternatives: (1) DECON which assumes decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR generally has a 30-year delay prior to onset of decommissioning activities, and (3) SAFSTOR which assumes the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated generally within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible untilDOE acceptance for disposal. The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be influenced by multiple factors including the funding status of the NDT fund at the time of shutdown. The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an extended 70
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60-year nuclear license term (regardless of whether such 20-year license extension has been received for each unit), (3) the probability of a second, 20-year license renewal for some nuclear units, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. As power market and regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates. Generation's probabilistic cash flow models also include an assessment of the timing ofDOE acceptance of SNF for disposal. Generation currently assumesDOE will begin accepting SNF in 2035. The SNF acceptance date assumption is based on management's estimates of the amount of time required forDOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding the estimated date whenDOE will begin accepting SNF, see Note 19 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. Generation initially recognizes an ARO at fair value and subsequently adjusts it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO as a result of upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, is measured using the average historical CARFR rates used in creating the initial ARO cost layers. If Generation's future nominal cash flows associated with the ARO were to be discounted at current prevailing CARFR, the obligation would increase from approximately$11.9 billion to approximately$15.0 billion . The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO (dollars in millions):
(Decrease) Increase
to ARO at December
Change in the CARFR applied to the annual ARO update 31, 2020
2019 CARFR rather than the 2020 CARFR $ (370)
2020 CARFR increased by 50 basis points
(390)
2020 CARFR decreased by 50 basis points
490
ARO Sensitivities. Changes in the assumptions underlying the ARO could
materially affect the decommissioning obligation. The impact to the ARO of a
change in any one of these assumptions is highly dependent on how the other
assumptions may correspondingly change.
The following table illustrates the effects of changing certain ARO assumptions
while holding all other assumptions constant (dollars in millions):
Increase to ARO at
Change in ARO Assumption December 31, 2020
Cost escalation studies
Uniform increase in escalation rates of 50 basis points $ 2,560
Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 10 percent
1,050
Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent(a)
610
Shorten each unit's probability weighted operating life assumption by 10 percent(b)
1,690
Extend the estimated date for DOE acceptance of SNF to 2040 280
__________
(a)Excludes any sites in which management has committed to a specific decommissioning approach. (b)Excludes any retired sites.
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See Note 1 - Significant Accounting Policies, Note 7 - Early Plant Retirements and Note 10 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs.Goodwill (Exelon, ComEd, and PHI) As ofDecember 31, 2020 , Exelon's$6.7 billion carrying amount of goodwill consists primarily of$2.6 billion at ComEd and$4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating segment and reporting unit. PHI's operating segments and reporting units are Pepco, DPL, and ACE. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd's goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI's goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of$2.1 billion ,$1.4 billion , and$0.5 billion , respectively. See Note 13 - Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses and the fair value of debt. While the 2020 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, or PHI's goodwill, which could be material. See Note 1 - Significant Accounting Policies and Note 13 - Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Unamortized Energy Contract Assets and Liabilities (Exelon, Generation , and PHI) Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has acquired and the electricity contracts Exelon acquired as part of the PHI merger. The initial amount recorded represents the fair value of the contracts at the time of acquisition. At Exelon and PHI, offsetting regulatory assets or liabilities were also recorded for those energy contract costs that are probable of recovery or refund through customer rates. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract assets and liabilities is recorded through purchased power and fuel expense or operating revenues, depending on the nature of the underlying contract. See Note 3 - Regulatory Matters and Note 13 - Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Impairment of Long-Lived Assets (All Registrants) All Registrants regularly monitor and evaluate the carrying value of long-lived assets and asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, an asset remaining idle for more than a short period of time, specific regulatory disallowance, advances in technology, plans to dispose of a long-lived asset 72
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significantly before the end of its useful life, and financial distress of a
third party for assets contracted with them on a long-term basis, among others.
The review of long-lived assets and asset groups for impairment utilizes
significant assumptions about operating strategies and estimates of future cash
flows, which require assessments of current and projected market conditions. For
the generation business, forecasting future cash flows requires assumptions
regarding forecasted commodity prices for the sale of power and purchases of
fuel and the expected operations of assets. A variation in the assumptions used
could lead to a different conclusion regarding the recoverability of an asset or
asset group and, thus, could potentially result in material future impairments.
An impairment evaluation is based on an undiscounted cash flow analysis at the
lowest level at which cash flows of the long-lived assets or asset groups are
largely independent of the cash flows of other assets and liabilities. For the
generation business, the lowest level of independent cash flows is determined by
the evaluation of several factors, including the geographic dispatch of the
generation units and the hedging strategies related to those units as well as
the associated intangible assets or liabilities recorded on the balance sheet.
The cash flows from the generating units are generally evaluated at a regional
portfolio level with cash flows generated from the customer supply and risk
management activities, including cash flows from related intangible assets and
liabilities on the balance sheet. In certain cases, generating assets may be
evaluated on an individual basis where those assets are contracted on a
long-term basis with a third party and operations are independent of other
generating assets (typically contracted renewables). For such assets the
financial viability of the third party, including the impact of bankruptcy on
the contract, may be a significant assumption in the assessment.
On a quarterly basis, Generation assesses its long-lived assets or asset groups
for indicators of impairment. If indicators are present for a long-lived asset
or asset group, a comparison of the undiscounted expected future cash flows to
the carrying value is performed. When the undiscounted cash flow analysis
indicates the carrying value of a long-lived asset or asset group is not
recoverable, the amount of the impairment loss is determined by measuring the
excess of the carrying amount of the long-lived asset or asset group over its
fair value. The fair value of the long-lived asset or asset group is dependent
upon a market participant's view of the exit price of the assets. This includes
significant assumptions of the estimated future cash flows generated by the
assets and market discount rates. Events and circumstances often do not occur as
expected resulting in differences between prospective financial information and
actual results, which may be material. The determination of fair value is driven
by both internal assumptions that include significant unobservable inputs (Level
3) such as revenue and generation forecasts, projected capital, and maintenance
expenditures and discount rates, as well as information from various public,
financial and industry sources.
See Note 12 - Asset Impairments of the Combined Notes to Consolidated Financial
Statements for a discussion of asset impairment assessments.
Depreciable Lives of Property, Plant, and Equipment (All Registrants)
The Registrants have significant investments in electric generation assets and
electric and natural gas transmission and distribution assets. These assets are
generally depreciated on a straight-line basis, using the group, composite, or
unitary methods of depreciation. The group approach is typically for groups of
similar assets that have approximately the same useful lives and the composite
approach is used for heterogeneous assets that have different lives. Under both
methods, a reporting entity depreciates the assets over the average life of the
assets in the group. The estimation of asset useful lives requires management
judgment, supported by formal depreciation studies of historical asset
retirement experience. Depreciation studies are generally completed every five
years, or more frequently if required by a rate regulator or if an event,
regulatory action, or change in retirement patterns indicate an update is
necessary.
For the Utility Registrants, depreciation studies generally serve as the basis
for amounts allowed in customer rates for recovery of depreciation costs.
Generally, the Utility Registrants adjust their depreciation rates for financial
reporting purposes concurrent with adjustments to depreciation rates reflected
in customer rates, unless the depreciation rates reflected in customer rates do
not align with management's judgment as to an appropriate estimated useful life
or have not been updated on a timely basis. Depreciation expense and customer
rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the future
costs of dismantling and removing plant from service upon retirement. See Note 3
- Regulatory Matters of the Combined Notes to the Consolidated Financial
Statements for information regarding regulatory liabilities and assets recorded
by ComEd, BGE, Pepco, DPL, and ACE related to removal costs.
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PECO's removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies. At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities and reassesses the reasonableness of estimated useful lives whenever events or changes in circumstances warrant. When a determination has been made that an asset will be retired before the end of its current estimated useful life, depreciation provisions will be accelerated to reflect the shortened estimated useful life, which could have a material unfavorable impact on Exelon's and Generation's future results of operations. See Note 7 - Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information. Changes in estimated useful lives of electric generation assets and of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants' future results of operations. See Note 1 - Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants. Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants) Exelon sponsors defined benefit pension plans and OPEB plans for substantially all current employees. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. Pension and OPEB plan assets include equity securities, includingU.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity, and hedge funds. Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon's target asset class allocations. Exelon calculates the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV. Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates. Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon's mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2020 improvement scale adjusted to use Proxy SSA ultimate improvement rates. 74
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Sensitivity to Changes in Key Assumptions. The following tables illustrate the
effects of changing certain of the actuarial assumptions discussed above, while
holding all other assumptions constant (dollars in millions):
Actual Assumption
Change in
Actuarial Assumption Pension OPEB Assumption Pension OPEB Total
Change in 2020 cost:
Discount rate(a) 3.34% 3.31% 0.5% $ (52) $ (14) $ (66)
3.34% 3.31% (0.5)% 70 15 85
EROA 7.00% 6.69% 0.5% (91) (12) (103)
7.00% 6.69% (0.5)% 91 12 103
Change in benefit obligation
at December 31, 2020 :
Discount rate(a) 2.58% 2.51% 0.5% (1,410) (268) (1,678)
2.58% 2.51% (0.5)% 1,631 309 1,940
__________
(a)In general, the discount rate will have a larger impact on the pension and
OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount
rate sensitivities above cannot necessarily be extrapolated for larger increases
or decreases in the discount rate. Additionally, Exelon utilizes a
liability-driven investment strategy for its pension asset portfolio. The
sensitivities shown above do not reflect the offsetting impact that changes in
discount rates may have on pension asset returns.
See Note 1 - Significant Accounting Policies and Note 15 - Retirement Benefits
of the Combined Notes to Consolidated Financial Statements for additional
information regarding the accounting for the defined benefit pension plans and
OPEB plans.
Regulatory Accounting (Exelon and Utility Registrants)
For their regulated electric and gas operations, Exelon and the Utility
Registrants reflect the effects of cost-based rate regulation in their financial
statements, which is required for entities with regulated operations that meet
the following criteria: (1) rates are established or approved by a third-party
regulator; (2) rates are designed to recover the entities' cost of providing
services or products; and (3) a reasonable expectation that rates designed to
recover costs can be charged to and collected from customers. Regulatory assets
represent incurred costs that have been deferred because of their probable
future recovery from customers through regulated rates. Regulatory liabilities
represent (1) revenue or gains that have been deferred because it is probable
such amounts will be returned to customers through future regulated rates; or
(2) billings in advance of expenditures for approved regulatory programs. If it
is concluded in a future period that a separable portion of operations no longer
meets the criteria discussed above, Exelon and the Utility Registrants would be
required to eliminate any associated regulatory assets and liabilities and the
impact, which could be material, would be recognized in the Consolidated
Statements of Operations and Comprehensive Income.
The following table illustrates the gains (losses) that could result from the
elimination of regulatory assets and liabilities and charges against OCI
(dollars in millions before taxes) related to deferred costs associated with
Exelon's pension and OPEB plans that are recorded as regulatory assets in
Exelon's Consolidated Balance Sheets:
December 31, 2020 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Gain (loss) $ 79 $ 4,664 $ (177) $ 490 $ (798) $ (94) $ 260 $ (152)
Charge against OCI(a) $ 3,984 $ - $ - $ - $ - $ - $ - $ -
___________
(a)Exelon's charge against OCI (before taxes) consists of up to$2.7 billion ,$481 million ,$193 million ,$387 million ,$188 million , and$91 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability of$(36) million (before taxes) related to PECO's portion of the deferred costs associated with Exelon's OPEB plans that would result in an increase in OCI if reversed. 75
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See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities tables of Exelon and the Utility Registrants. For each regulatory jurisdiction in which they conduct business, Exelon and the Utility Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material. Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, andFERC transmission formula rate tariffs for the Utility Registrants. Accounting for Derivative Instruments (All Registrants) The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk, and interest rate risk related to ongoing business operations. The Registrants' derivative activities are in accordance with Exelon's Risk Management Policy (RMP). See Note 16 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlyings and one or more notional quantities. Changes in management's assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope of new authoritative guidance. All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives entered into for economic hedging and for proprietary trading purposes are recorded at fair value through earnings. For economic hedges that are not designated for hedge accounting for the Utility Registrants, changes in the fair value each period are generally recorded with a corresponding offsetting regulatory asset or liability given likelihood of recovering the associated costs through customer rates. NPNS. As part of Generation's energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated by Generation as NPNS transactions, which are thus not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed. Contracts that qualify for the NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of ComEd's energy procurement process, PECO's full requirement contracts under the PAPUC-approved DSP program, most of PECO's natural gas supply agreements, all of BGE's full requirement contracts and natural gas supply agreements that are derivatives, and certain Pepco, DPL, and ACE full requirement contracts qualify for and are accounted for under the NPNS. Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP. 76
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As a part of the authoritative guidance, the Registrants make estimates and
assumptions concerning future commodity prices, load requirements, interest
rates, the timing of future transactions and their probable cash flows, the fair
value of contracts and the expected changes in the fair value in deciding
whether or not to enter into derivative transactions, and in determining the
initial accounting treatment for derivative transactions. Under the
authoritative guidance for fair value measurements, the Registrants categorize
these derivatives under a fair value hierarchy that prioritizes the inputs to
valuation techniques used to measure fair value.
Derivative contracts are traded in both exchange-based and non-exchange-based
markets. Exchange-based derivatives that are valued using unadjusted quoted
prices in active markets are generally categorized in Level 1 in the fair value
hierarchy.
Certain derivatives' pricing is verified using indicative price quotations
available through brokers or over-the-counter, on-line exchanges. The price
quotations reflect the average of the bid-ask mid-point from markets that the
Registrants believe provide the most liquid market for the commodity. The price
quotations are reviewed and corroborated to ensure the prices are observable and
representative of an orderly transaction between market participants. The
Registrant's derivatives are traded predominately at liquid trading points. The
remaining derivative contracts are valued using models that consider inputs such
as contract terms, including maturity, and market parameters, and assumptions of
the future prices of energy, interest rates, volatility, credit worthiness, and
credit spread. For derivatives that trade in liquid markets, such as generic
forwards, swaps, and options, the model inputs are generally observable. Such
instruments are categorized in Level 2.
For derivatives that trade in less liquid markets with limited pricing
information, the model inputs generally would include both observable and
unobservable inputs and are categorized in Level 3.
The Registrants consider nonperformance risk, including credit risk in the
valuation of derivative contracts, including both historical and current market
data in its assessment of nonperformance risk, including credit risk. The
impacts of nonperformance and credit risk to date have generally not been
material to the financial statements.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note
18 - Fair Value of Financial Assets and Liabilities and Note 16 - Derivative
Financial Instruments of the Combined Notes to Consolidated Financial Statements
for additional information regarding the Registrants' derivative instruments.
Taxation (All Registrants)
Significant management judgment is required in determining the Registrants'
provisions for income taxes, primarily due to the uncertainty related to tax
positions taken, as well as deferred tax assets and liabilities and valuation
allowances. The Registrants account for uncertain income tax positions using a
benefit recognition model with a two-step approach including a
more-likely-than-not recognition threshold and a measurement approach based on
the largest amount of tax benefit that is greater than 50% likely of being
realized upon ultimate settlement. Management evaluates each position based
solely on the technical merits and facts and circumstances of the position,
assuming the position will be examined by a taxing authority having full
knowledge of all relevant information. Significant judgment is required to
determine whether the recognition threshold has been met and, if so, the
appropriate amount of tax benefits to be recorded in the Registrants'
consolidated financial statements.
The Registrants evaluate quarterly the probability of realizing deferred tax
assets by reviewing a forecast of future taxable income and their intent and
ability to implement tax planning strategies, if necessary, to realize deferred
tax assets. The Registrants also assess negative evidence, such as the
expiration of historical operating loss or tax credit carryforwards, that could
indicate the Registrant's inability to realize its deferred tax assets. Based on
the combined assessment, the Registrants record valuation allowances for
deferred tax assets when it is more-likely-than-not such benefit will not be
realized in future periods.
Actual income taxes could vary from estimated amounts due to the future impacts
of various items, including future changes in income tax laws, the Registrants'
forecasted financial condition and results of operations, failure to
successfully implement tax planning strategies, as well as results of audits and
examinations of filed tax returns by taxing authorities. See Note 14 - Income
Taxes of the Combined Notes to Consolidated Financial Statements for additional
information.
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Accounting for Loss Contingencies (All Registrants)
In the preparation of their financial statements, the Registrants make judgments
regarding the future outcome of contingent events and record liabilities for
loss contingencies that are probable and can be reasonably estimated based upon
available information. The amount recorded may differ from the actual expense
incurred when the uncertainty is resolved. Such difference could have a
significant impact in the Registrants' consolidated financial statements.
Environmental Costs. Environmental investigation and remediation liabilities are
based upon estimates with respect to the number of sites for which the
Registrants will be responsible, the scope and cost of work to be performed at
each site, the portion of costs that will be shared with other parties, the
timing of the remediation work and changes in technology, regulations, and the
requirements of local governmental authorities. Annual studies and/or reviews
are conducted at ComEd, PECO, BGE, and DPL to determine future remediation
requirements for MGP sites and estimates are adjusted accordingly. In addition,
periodic reviews are performed at each of the Registrants to assess the adequacy
of other environmental reserves. These matters, if resolved in a manner
different from the estimate, could have a significant impact in the Registrants'
consolidated financial statements. See Note 19 - Commitments and Contingencies
of the Combined Notes to Consolidated Financial Statements for additional
information.
Other, Including Personal Injury Claims. The Registrants are self-insured for
general liability, automotive liability, workers' compensation, and personal
injury claims to the extent that losses are within policy deductibles or exceed
the amount of insurance maintained. The Registrants have reserves for both open
claims asserted and an estimate of claims incurred but not reported (IBNR). The
IBNR reserve is estimated based on actuarial assumptions and analysis and is
updated annually. Future events, such as the number of new claims to be filed
each year, the average cost of disposing of claims, as well as the numerous
uncertainties surrounding litigation and possible state and national legislative
measures could cause the actual costs to be higher or lower than estimated.
Accordingly, these claims, if resolved in a manner different from the estimate,
could have a material impact in the Registrants' consolidated financial
statements.
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Revenue Recognition (All Registrants) Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from various business activities including: the sale of power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services. The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, Derivative and ARP guidance to recognize revenue as discussed in more detail below. Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas, and other energy-related commodities are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS, sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with ISOs. The determination of Generation's and the Utility Registrants' retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities' customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternate supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 - Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. Derivative Revenues. The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses. Alternative Revenue Program Accounting. Certain of the Utility Registrants' ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants' formula rate mechanisms and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of "originating" ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the "originating" ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers. ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC andFERC in accordance with its formula rate mechanisms. BGE, Pepco, and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates 79
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that they believe are probable of approval byFERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Allowance for Credit Losses on Customer Accounts Receivable (Utility Registrants) Utility Registrants estimate the allowance for credit losses on customer receivables by applying loss rates developed specifically for each company based on historical loss experience, current conditions, and forward-looking risk factors to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various attributes, including delinquency of their balances and payment history and represent expected, future customer behavior. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Utility Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU regulations. 80
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Generation
Results of Operations by Registrant
Results of Operations-Generation
Generation's Results of Operations includes discussion of RNF, which is a
financial measure not defined under GAAP and may not be comparable to other
companies' presentations or deemed more useful than the GAAP information
provided elsewhere in this report. The CODMs for Exelon and Generation evaluate
the performance of Generation's electric business activities and allocate
resources based on RNF. Generation believes that RNF is a useful measure because
it provides information that can be used to evaluate its operational
performance.
(Unfavorable)
2020 2019 Favorable Variance
Operating revenues $ 17,603 $ 18,924 $ (1,321)
Purchased power and fuel expense 9,585 10,856 1,271
Revenues net of purchased power
and fuel expense 8,018 8,068 (50)
Other operating expenses
Operating and maintenance 5,168 4,718 (450)
Depreciation and amortization 2,123 1,535 (588)
Taxes other than income taxes 482 519 37
Total other operating expenses 7,773 6,772 (1,001)
Gain on sales of assets and businesses 11 27 (16)
Operating income 256 1,323 (1,067)
Other income and (deductions)
Interest expense (357) (429) 72
Other, net 937 1,023 (86)
Total other income and (deductions) 580 594 (14)
Income before income taxes 836 1,917 (1,081)
Income taxes 249 516 267
Equity in losses of unconsolidated affiliates (8) (184) 176
Net income 579 1,217 (638)
Net (loss) income attributable to noncontrolling
interests (10) 92 (102)
Net income attributable to membership interest
1,125 $ (536) Year EndedDecember 31, 2020 Compared to Year EndedDecember 31, 2019 . Net income attributable to membership interest decreased by$536 million primarily due to: •One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retireByron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of accelerated depreciation and amortization due to the early retirement of TMI inSeptember 2019 ; •Impairment of theNew England asset group; •Lower capacity revenue; •Reduction in load due to COVID-19; 81
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Generation
•Lower realized energy prices; •Higher nuclear outage days; •Impact of Generation's annual update to the nuclear ARO for Non-regulatory Agreement Units; •Lower net unrealized and realized gains on NDT funds; •COVID-19 direct costs; and The decreases were partially offset by: •Higher mark-to-market gains; •Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair valued based on quoted market prices of the stocks as ofDecember 31, 2020 ; •Lower operating and maintenance expense primarily due to previous cost management programs, lower contracting costs, and lower travel costs partially offset by lower NEIL insurance distributions; •Lower nuclear fuel costs; •Lower depreciation and amortization expense due to the impact of extending the operating license atPeach Bottom ;
•A tax benefit related to a settlement in the first quarter of 2020, partially offset by the absence of a tax benefit related to certain research and development activities recorded in the fourth quarter of 2019.
Revenues Net ofPurchased Power and Fuel Expense. The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest,New York ,ERCOT , and Other Power Regions. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments. The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues. Generation evaluates the operating performance of electric business activities using the measure of RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, 82
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Generation
and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements. For the years endedDecember 31, 2020 compared to 2019, RNF by region were as follows. See Note 5 - Segment Information of the Combined Notes to the Consolidated Financial Statements for additional information on Purchase power and fuel expense for Generation's reportable segments. 2020 vs. 2019 2020 2019 Variance % Change Mid-Atlantic(a)$ 2,204 $ 2,655 $ (451) (17.0) % Midwest(b) 2,902 2,962 (60) (2.0) % New York 997 1,094 (97) (8.9) % ERCOT 426 308 118 38.3 % Other Power Regions 665 620 45 7.3 %
Total electric revenues net of purchased power and fuel expense
7,194 7,639 (445) (5.8) %
Mark-to-market gains (losses) 295 (215) 510 237.2 %
Other 529 644 (115) (17.9) %
Total revenue net of purchased power and fuel expense
(0.6) %
__________
(a)Includes results of transactions with PECO, BGE, Pepco, DPL, and ACE. (b)Includes results of transactions with ComEd.
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Generation
Generation's supply sources by region are summarized below:
2020 vs. 2019
Supply Source (GWhs) 2020 2019 Variance % Change
Nuclear Generation(a)
Mid-Atlantic 52,202 58,347 (6,145) (10.5) %
Midwest 96,322 94,890 1,432 1.5 %
New York 26,561 28,088 (1,527) (5.4) %
Total Nuclear Generation 175,085 181,325 (6,240) (3.4) %
Fossil and Renewables
Mid-Atlantic 2,206 2,884 (678) (23.5) %
Midwest 1,240 1,374 (134) (9.8) %
New York 4 5 (1) (20.0) %
ERCOT 11,982 13,572 (1,590) (11.7) %
Other Power Regions 11,121 11,476 (355) (3.1) %
Total Fossil and Renewables 26,553 29,311 (2,758) (9.4) %
Purchased Power
Mid-Atlantic 22,487 14,790 7,697 52.0 %
Midwest 770 1,424 (654) (45.9) %
ERCOT 5,636 4,821 815 16.9 %
Other Power Regions 51,079 48,673 2,406 4.9 %
Total Purchased Power 79,972 69,708 10,264 14.7 %
Total Supply/Sales by Region(c)
Mid-Atlantic(b) 76,895 76,021 874 1.1 %
Midwest(b) 98,332 97,688 644 0.7 %
New York 26,565 28,093 (1,528) (5.4) %
ERCOT 17,618 18,393 (775) (4.2) %
Other Power Regions 62,200 60,149 2,051 3.4 %
Total Supply/Sales by Region 281,610 280,344 1,266 0.5 %
__________
(a)Includes the proportionate share of output where Generation has an undivided
ownership interest in jointly-owned generating plants and includes the total
output of plants that are fully consolidated (e.g. CENG).
(b)Includes affiliate sales to PECO, BGE, Pepco, DPL, and ACE in the
Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
(c)Reflects a decrease in load due to COVID-19.
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Generation
For the years endedDecember 31, 2020 compared to 2019 changes in RNF by region were as follows: 2020 vs. 2019 (Decrease)/Increase Description Mid-Atlantic $ (451)
• decreased revenue due to the permanent cease of
generation operations at TMI in the third quarter
of 2019
• decreased capacity revenues
• lower realized energy prices, partially offset
by
• increase in newly contracted load offset by
impacts of COVID-19
• increased ZEC revenues due to the approval of
the NJ ZEC program in the second quarter of 2019
Midwest (60) • decreased capacity revenues
• lower realized energy prices
• decreased load due to COVID-19 offset by an
increase in total ISO sales, partially offset by
• decreased nuclear outage days
New York (97) • increased nuclear outage days
• decreased ZEC revenues due to increased outage
days
• lower realized energy prices
• decreased load due to COVID-19 offset by newly
contracted load, partially offset by
• increased capacity revenues
ERCOT 118 • lower procurement costs for owned and
contracted assets
• higher portfolio optimization, partially offset
by
• lower realized energy prices
Other Power Regions 45 • higher portfolio optimization
• increase in newly contracted load offset by
impacts of COVID-19, partially offset by
• decreased capacity revenues
• lower realized energy prices
Mark-to-market(a) 510
• gains on economic hedging activities of
million in 2020 compared to losses of
million in 2019
Other (115) • increase in accelerated nuclear fuel
amortization associated with announced early
plant retirements • decreased revenue related to
the energy efficiency business
Total $ (50)
__________
(a)See Note 16 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.
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Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excludingSalem , which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies' presentations or be more useful than the GAAP information provided elsewhere in this report. 2020 2019 Nuclear fleet capacity factor 95.4 % 95.7 % Refueling outage days 260 209 Non-refueling outage days 19 51 The changes in Operating and maintenance expense, consisted of the following: 2020 vs. 2019 Increase (Decrease) Asset Impairments $ 499 ARO update 125
Nuclear refueling outage costs, including the co-owned
60
Insurance 52
COVID-19 direct costs 46
Litigation settlements 26
Change in environmental liabilities 18
Credit loss expense(a) 16
Accretion expense 14
Plant retirements and divestitures (8)
Pension and non-pension postretirement benefits expense (19)
Corporate allocations (35)
Travel costs (38)
Other (71)
Labor, other benefits, contracting, and materials(b) (235)
Total increase $ 450
__________
(a)Increased credit loss expense including impacts from COVID-19.
(b)Primarily reflects decreased costs related to the permanent cease of
generation operations at TMI, lower labor costs resulting from previous cost
management programs, and decreased contracting costs.
Depreciation and amortization expense for the year ended December 31, 2020
compared to the same period in 2019 increased primarily due to the accelerated
depreciation and amortization associated with Generation's decision to early
retire the Byron and Dresden nuclear facilities, partially offset by the
permanent cease of generation operations at TMI.
Taxes other than income taxes for the year ended December 31, 2020 compared to
the same period in 2019 decreased primarily due to decreased sales and power
usage.
Gain on sales of assets and businesses for the year ended December 31, 2020
compared to the same period in 2019 decreased primarily due to Generation's gain
on sale of certain wind assets in 2019 partially offset by the loss on sale of
Oyster Creek .
Other, net for the year ended December 31, 2020 compared to the same period in
2019 decreased due to activity associated with NDT funds as described in the
table below.
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Generation
2020 2019
Net unrealized gains on NDT funds(a) $ 391 $ 411
Net realized gains on sale of NDT funds(a) 70 253
Interest and dividend income on NDT funds(a) 90 110 Contractual elimination of income tax expense(b) 180 216 Unrealized gains from equity investments(c) 186
-
Other 20 33
Total other, net $ 937 $ 1,023
__________
(a)Unrealized gains, realized gains, and interest and dividend income on the NDT
funds are associated with the Non-Regulatory Agreement Units.
(b)Contractual elimination of income tax expense is associated with the income
taxes on the NDT funds of the Regulatory Agreement Units.
(c)Unrealized gains resulting from equity investments without readily
determinable fair values that became publicly traded entities in the fourth
quarter of 2020 and were fair valued based on quoted market prices of the stocks
as of December 31, 2020 .
Interest Expense for the year ended December 31, 2020 compared to the same
period in 2019 decreased primarily due to the redemption of long-term debt in
2020.
Effective income tax rates were 29.8% and 26.9% for the years ended December 31,
2020 and 2019, respectively. The change in 2020 is primarily related to one-time
income tax settlements partially offset by the absence of research and
development refund claims. See Note 14 - Income Taxes of the Combined Notes to
Consolidated Financial Statements for additional information.
Equity in losses of unconsolidated affiliates for the year ended December 31,
2020 compared to the same period in 2019 increased primarily due to the
impairment of equity method investments in certain distributed energy companies
in the third quarter of 2019.
Net income attributable to noncontrolling interests for the year ended
December 31, 2020 compared to the same period in 2019 decreased primarily due to
lower unrealized losses on NDT fund investments for CENG.
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ComEd
Results of Operations-ComEd
Favorable
(Unfavorable)
2020 2019 Variance
Operating revenues $ 5,904 $ 5,747 $ 157
Operating expenses
Purchased power expense 1,998 1,941 (57)
Operating and maintenance 1,520 1,305 (215)
Depreciation and amortization 1,133 1,033 (100)
Taxes other than income taxes 299 301 2
Total operating expenses 4,950 4,580 (370)
Gain on sales of assets - 4 (4)
Operating income 954 1,171 (217)
Other income and (deductions)
Interest expense, net (382) (359) (23)
Other, net 43 39 4
Total other income and (deductions) (339) (320) (19)
Income before income taxes 615 851 (236)
Income taxes 177 163 (14)
Net income $ 438 $ 688 $ (250)
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 . Net
income decreased by $250 million primarily due to payments that ComEd made under
the Deferred Prosecution Agreement, an impairment charge resulting from
acquisition of transmission assets, and lower allowed electric distribution ROE
due to a decrease in treasury rates, partially offset by higher electric
distribution formula rate earnings (reflecting the impacts of higher rate base).
See Note 19 - Commitments and Contingencies of the Combined Notes to
Consolidated Financial Statements for additional information related to the
Deferred Prosecution Agreement.
The changes in Operating revenues consisted of the following:
2020 vs. 2019
Increase
Energy efficiency $ 37
Electric distribution 36
Transmission 2
Other 29
104
Regulatory required programs 53
Total increase $ 157
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms implemented pursuant to FEJA.
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ComEd
Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the year endedDecember 31, 2020 , as compared to the same period in 2019, primarily due to increased regulatory asset amortization which is fully recoverable. See Depreciation and amortization expense discussions below and Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. During the year endedDecember 31, 2020 , as compared to the same period in 2019, electric distribution revenue increased due to the impact of higher rate base and higher fully recoverable costs, offset by lower allowed ROE due to a decrease in treasury rates. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Transmission Revenue. Under aFERC -approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. During the year endedDecember 31, 2020 , as compared to the same period in 2019, transmission revenues remained relatively consistent. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. The increase in Other revenue for the year endedDecember 31, 2020 , as compared to the same period in 2019, primarily reflects mutual assistance revenues associated with storm restoration efforts. Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, and costs related to electricity, ZEC, and REC procurement. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation. The increase of$57 million for the year endedDecember 31, 2020 , as compared to the same period in 2019, in Purchased power expense is offset in Operating revenues as part of regulatory required programs. 89
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ComEd
The changes in Operating and maintenance expense consisted of the following:
2020 vs. 2019
Increase (Decrease)
Deferred Prosecution Agreement payments(a) $ 200
BSC costs
20
Labor, other benefits, contracting, and materials
7
Pension and non-pension postretirement benefits expense 5
Storm-related costs(b) (12)
Other(c) (4)
216
Regulatory required programs(d) (1)
Total increase $ 215
__________
(a)See Note 19 - Commitments and Contingencies of the Combined Notes to
Consolidated Financial Statements for additional information.
(b)For the year ended December 31, 2020 , the decrease primarily reflects lower
storm costs as a result of the August 2020 storm costs being reclassified to a
regulatory asset.
(c)For the year ended December 31, 2020 , the decrease primarily reflects lower
travel costs offset by an impairment charge related to acquisition of
transmission assets.
(d)ComEd is allowed to recover from or refund to customers the difference
between its annual credit loss expense and the amounts collected in rates
annually through a rider mechanism.
The changes in Depreciation and amortization expense consisted of the following:
2020 vs. 2019
Increase
Regulatory asset amortization(a) $ 64
Depreciation and amortization expense(b) 36
Total increase $ 100
__________
(a)Includes amortization of ComEd's energy efficiency formula rate regulatory asset and amortization related to theAugust 2020 storm regulatory asset. (b)Reflects ongoing capital expenditures. Interest Expense, net increased$23 million for the year endedDecember 31, 2020 , as compared to the same period in 2019, primarily due to the issuance of debt inFebruary 2020 . Effective income tax rates for the years endedDecember 31, 2020 and 2019, were 28.8% and 19.2%, respectively. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 90
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PECO
Results of Operations-PECO
(Unfavorable)
2020 2019 Favorable Variance
Operating revenues $ 3,058 $ 3,100 $ (42)
Operating expenses
Purchased power and fuel expense 1,018 1,029 11
Operating and maintenance 975 861 (114)
Depreciation and amortization 347 333 (14)
Taxes other than income taxes 172 165 (7)
Total operating expenses 2,512 2,388 (124)
Gain on sales of assets - 1 (1)
Operating income 546 713 (167)
Other income and (deductions)
Interest expense, net (147) (136) (11)
Other, net 18 16 2
Total other income and (deductions) (129) (120) (9)
Income before income taxes 417 593 (176)
Income taxes (30) 65 95
Net income $ 447 $ 528 $ (81)
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 . Net
income decreased by $81 million primarily due to unfavorable weather conditions,
higher storm costs due to the June and August 2020 storms net of tax repairs,
increased depreciation and amortization expense, and increased interest expense,
partially offset by favorable volume and an increase in the tax repairs
deduction.
The changes in Operating revenues consisted of the following:
2020 vs. 2019
(Decrease) Increase
Electric Gas Total
Weather $ (29) $ (21) $ (50)
Volume 12 (3) 9
Pricing 2 6 8
Transmission 11 - 11
Other (7) (1) (8)
(11) (19) (30)
Regulatory required programs 65 (77) (12)
Total increase (decrease) $ 54 $ (96) $ (42)
Weather. The demand for electricity and natural gas is affected by weather
conditions. With respect to the electric business, very warm weather in summer
months and, with respect to the electric and natural gas businesses, very cold
weather in winter months are referred to as "favorable weather conditions"
because these weather conditions result in increased deliveries of electricity
and natural gas. Conversely, mild weather reduces demand. For the year ended
December 31, 2020 compared to the same period in 2019, Operating revenues
related to weather decreased due to the impact of unfavorable weather conditions
in PECO's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand
for energy needed to heat or cool a home or business. Normal weather is
determined based on historical average heating and cooling degree days for a
30-year period in PECO's service territory. The changes in heating and cooling
degree days in PECO's service territory for the years ended December 31, 2020
compared to the same period in 2019 and normal weather consisted of the
following:
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PECO
For the Years Ended December 31, % Change
Heating and Cooling Degree-Days 2020 2019 Normal 2020 vs. 2019 2019 vs. Normal
Heating Degree-Days 3,959 4,307 4,437 (8.1) % (10.8) %
Cooling Degree-Days 1,521 1,610 1,423 (5.5) % 6.9 %
Volume. Electric volume, exclusive of the effects of weather, for the year ended
December 31, 2020 compared to the same period in 2019, increased due to an
increase in usage for residential customers during COVID-19 further increased by
customer growth. Natural gas volume for the year ended December 31, 2020
compared to the same period in 2019, decreased on a net basis due to a decrease
in usage for the commercial and industrial natural gas classes during COVID-19.
% Change Weather - Normal
Electric Retail Deliveries to Customers (in GWhs) 2020 2019 2020 vs. 2019 % Change(b)
Retail Deliveries(a)
Residential 14,041 13,650 2.9 % 5.6 %
Small commercial & industrial 7,210 7,983 (9.7) % (8.2) %
Large commercial & industrial 13,669 14,958 (8.6) % (8.5) %
Public authorities & electric railroads 575 725 (20.7) % (20.7) %
Total electric retail deliveries 35,495 37,316 (4.9) % (3.5) %
__________
(a)Reflects delivery volumes and revenue from customers purchasing electricity
directly from PECO and customers purchasing electricity from a competitive
electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on
the historical 30-year average.
As of December 31,
Number of Electric Customers 2020 2019
Residential 1,508,622 1,494,462
Small commercial & industrial 154,421
154,000
Large commercial & industrial 3,101
3,104
Public authorities & electric railroads 10,206 10,039
Total 1,676,350 1,661,605
% Change Weather - Normal
Natural Gas Deliveries to customers (in mmcf) 2020 2019 2020 vs. 2019 % Change(b)
Retail Deliveries(a)
Residential 38,272 40,196 (4.8) % 1.6 %
Small commercial & industrial 19,341 23,828 (18.8) % (6.6) %
Large commercial & industrial 36 50 (28.0) % (11.9) %
Transportation 24,533 25,822 (5.0) % (2.9) %
Total natural gas deliveries 82,182 89,896 (8.6) % (1.8) %
__________
(a)Reflects delivery volumes and revenue from customers purchasing electricity
directly from PECO and customers purchasing electricity from a competitive
electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on
the historical 30-year average.
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PECO
As of December 31,
Number of Gas Customers 2020 2019
Residential 492,298 487,337
Small commercial & industrial 44,472 44,374
Large commercial & industrial 5 2
Transportation 713 730
Total 537,488 532,443
Pricing for the year ended December 31, 2020 compared to the same period in 2019
increased primarily due to higher overall effective rates due to decreased usage
across all major customer classes. Additionally, the increase represents revenue
from higher natural gas distribution rates.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies
from year to year based upon fluctuations in the underlying costs and capital
investments being recovered. PECO's transmission formula rate filing was
approved in the fourth quarter of 2019.
Other Revenue primarily includes revenue related to late payment charges. Other
revenues for the year ended December 31, 2020 compared to the same period in
2019, decreased as PECO ceased new late fees for all customers and restored
service to customers upon request who were disconnected in the last twelve
months beginning March of 2020.
Regulatory Required Programs represents revenues collected under approved riders
to recover costs incurred for regulatory programs such as energy efficiency,
PGC, and the GSA. The riders are designed to provide full and current cost
recovery as well as a return. The costs of these programs are included in
Purchased power and fuel expense, Operating and maintenance expense,
Depreciation and amortization expense, and Income taxes. Customers have the
choice to purchase electricity and natural gas from competitive electric
generation and natural gas suppliers. Customer choice programs do not impact the
volume of deliveries as PECO remains the distribution service provider for all
customers and charges a regulated rate for distribution service, which is
recorded in Operating revenues. For customers that choose to purchase electric
generation or natural gas from competitive suppliers, PECO acts as the billing
agent and therefore does not record Operating revenues or Purchased power and
fuel expense related to the electricity and/or natural gas. For customers that
choose to purchase electric generation or natural gas from PECO, PECO is
permitted to recover the electricity, natural gas, and REC procurement costs
without mark-up and therefore records equal and offsetting amounts in Operating
revenues and Purchased power and fuel expense related to the electricity,
natural gas, and RECs.
See Note 5-Segment Information of the Combined Notes to Consolidated Financial
Statements for the presentation of PECO's revenue disaggregation.
The decrease of $11 million for the year ended December 31, 2020 compared to the
same period in 2019, respectively, in Purchased power and fuel expense is fully
offset in Operating revenues as part of regulatory required programs.
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PECO
The changes in Operating and maintenance expense consisted of the following:
2020 vs. 2019
Increase (Decrease)
Storm-related costs(a) $ 82
Labor, other benefits, contracting, and materials 23
Credit loss expense(b) 12
BSC costs 1
Pension and non-pension postretirement benefits expense (4)
Other 7
121
Regulatory Required Programs (7)
Total increase $ 114
__________
(a)Reflects increased storm costs due to June and August 2020 storms.
(b)Increased credit loss expense primarily as a result of suspending customer
disconnections, partially offset by the regulatory asset recorded in 2020
related to incremental credit loss expense due to COVID-19. See Note 3 -
Regulatory Matters of the Combined Notes to Consolidated Financial Statements
for additional information.
The changes in Depreciation and amortization expense consisted of the following:
2020 vs. 2019
Increase (Decrease)
Depreciation and amortization(a) $ 16
Regulatory asset amortization (2)
Total increase $ 14
__________
(a)Depreciation and amortization expense increased primarily due to ongoing
capital expenditures.
Interest expense, net increased $11 million for the year ended December 31, 2020
compared to the same period in 2019, respectively, primarily due to the issuance
of debt in June 2020 .
Effective income tax rates were (7.2)% and 11.0% for the years ended
December 31, 2020 and 2019, respectively. See Note 14 - Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information
of the change in effective income tax rates.
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BGE
Results of Operations-BGE
(Unfavorable)
2020 2019 Favorable Variance
Operating revenues $ 3,098 $ 3,106 $ (8)
Operating expenses
Purchased power and fuel expense 991 1,052 61
Operating and maintenance 789 760 (29)
Depreciation and amortization 550 502 (48)
Taxes other than income taxes 268 260 (8)
Total operating expenses 2,598 2,574 (24)
Operating income 500 532 (32)
Other income and (deductions)
Interest expense, net (133) (121) (12)
Other, net 23 28 (5)
Total other income and (deductions) (110) (93) (17)
Income before income taxes 390 439 (49)
Income taxes 41 79 38
Net income $ 349 $ 360 $ (11)
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 . Net
income remained relatively consistent primarily due to higher natural gas and
electric distribution rates, partially offset by increased depreciation and
amortization expense, increased interest expense, increased expense due to a
commitment to a multi-year small business grants program, and a decrease in
other revenues.
The changes in Operating revenues consisted of the following:
2020 vs. 2019
Increase (Decrease)
Electric Gas Total
Distribution $ 30 $ 54 $ 84
Transmission (3) - (3)
Other (14) (9) (23)
13 45 58
Regulatory required programs (55) (11) (66)
Total (decrease) increase $ (42) $ 34 $ (8)
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BGE
Revenue Decoupling. The demand for electricity and natural gas is affected by
weather and customer usage. However, Operating revenues are not impacted by
abnormal weather or usage per customer as a result of a bill stabilization
adjustment (BSA) that provides for a fixed distribution charge per customer by
customer class. While Operating revenues are not impacted by abnormal weather or
usage per customer, they are impacted by changes in the number of customers.
As of December 31,
Number of Electric Customers 2020 2019
Residential 1,190,678 1,177,333
Small commercial & industrial 114,173
114,504
Large commercial & industrial 12,478
12,322
Public authorities & electric railroads 267 268
Total 1,317,596 1,304,427
As of December 31,
Number of Gas Customers 2020 2019
Residential 647,188 639,426
Small commercial & industrial 38,267 38,345
Large commercial & industrial 6,101 6,037
Total 691,556 683,808
Distribution Revenue increased for the year ended December 31, 2020 compared to
the same period in 2019, primarily due to the impact of higher natural gas and
electric distribution rates that became effective in December 2019 .
Transmission Revenue. Under a FERC -approved formula, transmission revenue varies
from year to year based upon fluctuations in the underlying costs, capital
investments being recovered, and the highest daily peak load, which is updated
annually in January based on the prior calendar year. Generally,
increases/decreases in the highest daily peak load will result in higher/lower
transmission revenue. Transmission revenue decreased for the year ended
December 31, 2020 compared to the same period in 2019, primarily due to the
settlement agreement of transmission-related income tax regulatory liabilities,
partially offset by higher fully recoverable costs. See Note 3 - Regulatory
Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
Other Revenue includes revenue related to late payment charges, mutual
assistance, off-system sales, and service application fees. Other revenue
decreased for the year ended December 31, 2020 compared to the same period in
2019, as BGE temporarily suspended customer disconnections for non-payment
beginning March of 2020 and temporarily ceased new late fees for all customers
and restored service to customers upon request who were disconnected in the last
twelve months.
Regulatory Required Programs represent revenues collected under approved riders
to recover costs incurred for regulatory programs such as conservation, demand
response, STRIDE, and the POLR mechanism. The riders are designed to provide
full and current cost recovery, as well as a return in certain instances. The
costs of these programs are included in Purchased power and fuel expense,
Operating and maintenance expense, Depreciation and amortization expense, and
Taxes other than income taxes. Customers have the choice to purchase electricity
and natural gas from competitive electric generation and natural gas suppliers.
Customer choice programs do not impact the volume of deliveries as BGE remains
the distribution service provider for all customers and charges a regulated rate
for distribution service, which is recorded in Operating revenues. For customers
that choose to purchase electric generation or natural gas from competitive
suppliers, BGE acts as the billing agent and therefore does not record Operating
revenues or Purchased power and fuel expense related to the electricity and/or
natural gas. For customers that choose to purchase electric generation or
natural gas from BGE, BGE is permitted to recover the electricity and natural
gas procurement costs from customers and therefore records the amounts related
to the electricity and/or natural gas in Operating revenues and Purchased power
and fuel expense. BGE recovers electricity and natural gas procurement costs
from customers with a slight mark-up.
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BGE
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation. The decrease of$61 million for the year endedDecember 31, 2020 compared to the same period in 2019, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs. The changes in Operating and maintenance expense consisted of the following: 2020 vs. 2019 Increase
(Decrease)
Small business grants commitment(a) $ 15 BSC costs 13 Credit loss expense(b) 7 Labor, other benefits, contracting, and materials
(1)
Pension and non-pension postretirement benefits expense (2)
32
Regulatory required programs (3)
Total increase $ 29
__________
(a)Reflects increased charitable contributions as a result of a commitment in
2020 to a multi-year small business grants program.
(b)Increased credit loss expense primarily as a result of suspending customer
disconnections, partially offset by the regulatory asset recorded in 2020
related to incremental credit loss expense due to COVID-19. See Note 3 -
Regulatory Matters of the Combined Notes to Consolidated Financial Statements
for additional information.
The changes in Depreciation and amortization expense consisted of the following:
2020 vs. 2019
Increase
Depreciation and amortization(a) $ 35
Regulatory required programs 10
Regulatory asset amortization 3
Total increase $ 48
__________
(a)Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Taxes other than income increased for the year ended December 31, 2020 compared
to the same period in 2019, primarily due to higher property taxes.
Interest expense, net increased for the year ended December 31, 2020 compared to
the same period in 2019, primarily due to the issuance of debt in September 2019
and June 2020 .
Effective income tax rates were 10.5% and 18.0% for the years ended December 31,
2020 and 2019, respectively. The change is primarily related to the settlement
agreement of transmission-related income tax regulatory liabilities. See Note 3
- Regulatory Matters and Note 14 - Income Taxes of the Combined Notes to
Consolidated Financial Statements for additional information regarding the
components of the effective income tax rates.
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PHI
Results of Operations-PHI
PHI's Results of Operations include the results of its three reportable
segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary,
PHISCO, which provides a variety of support services and the costs are directly
charged or allocated to the applicable subsidiaries. Additionally, the results
of PHI's corporate operations include interest costs from various financing
activities. All material intercompany accounts and transactions have been
eliminated in consolidation. The following table sets forth PHI's GAAP
consolidated Net Income by Registrant for the year ended December 31, 2020
compared to the same period in 2019. See the Results of Operations for Pepco,
DPL, and ACE for additional information.
2020 2019 Favorable (Unfavorable) Variance
PHI $ 495 $ 477 $ 18
Pepco 266 243 23
DPL 125 147 (22)
ACE 112 99 13
Other(a) (8) (12) 4
__________
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate
operations, shared service entities, and other financing and investing
activities.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 . Net
income increased by $18 million primarily due to higher electric distribution
rates, higher transmission rates (net of the impact of the settlement agreement
of ongoing transmission-related income tax regulatory liabilities), and
decreased expense resulting from an absence of an increase in environmental
liabilities, and a gain on sale of land at Pepco in the fourth quarter of 2020,
partially offset by an increase in depreciation and amortization expense, an
increase in DPL storm costs related to the August 2020 storms in Delaware , an
increase in credit loss expense primarily as a result of suspending customer
disconnections partially offset by the regulatory asset recorded in 2020 related
to incremental credit loss expense due to COVID-19, and unfavorable weather
conditions in ACE and DPL Delaware's service territories.
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Pepco
Results of Operations-Pepco
(Unfavorable)
2020 2019 Favorable Variance
Operating revenues $ 2,149 $ 2,260 $ (111)
Operating expenses
Purchased power expense 602 665 63
Operating and maintenance 453 482 29
Depreciation and amortization 377 374 (3)
Taxes other than income taxes 367 378 11
Total operating expenses 1,799 1,899 100
Gain on sales of assets 9 - 9
Operating income 359 361 (2)
Other income and (deductions)
Interest expense, net (138) (133) (5)
Other, net 38 31 7
Total other income and (deductions) (100) (102) 2
Income before income taxes 259 259 -
Income taxes (7) 16 23
Net income $ 266 $ 243 $ 23
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 . Net
income increased by $23 million primarily due to decreased expense resulting
from an absence of an increase in environmental liabilities, increased electric
distribution revenues, and a gain on sale of land in the fourth quarter of 2020,
partially offset by an increase in depreciation and amortization expense and an
increase in credit loss expense primarily as a result of suspending customer
disconnections partially offset by the regulatory asset recorded in 2020 related
to incremental credit loss expense due to COVID-19.
The changes in Operating revenues consisted of the following:
2020 vs. 2019
Increase (Decrease)
Distribution 19
Transmission (36)
Other (3)
(20)
Regulatory required programs (91)
Total decrease $ (111)
Revenue Decoupling. The demand for electricity is affected by weather and
customer usage. However, Operating revenues from electric distribution in both
Maryland and the District of Columbia are not impacted by abnormal weather or
usage per customer as a result of a bill stabilization adjustment (BSA) that
provides for a fixed distribution charge per customer by customer class. While
Operating revenues are not impacted by abnormal weather or usage per customer,
they are impacted by changes in the number of customers.
As of December 31,
Number of Electric Customers 2020 2019
Residential 832,190 817,770
Small commercial & industrial 53,800 54,265
Large commercial & industrial 22,459 22,271
Public authorities & electric railroads 168 160
Total 908,617 894,466
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Pepco
Distribution Revenue increased for the year endedDecember 31, 2020 compared to the same period in 2019, primarily due to higher electric distribution rates inMaryland that became effective inAugust 2019 and customer growth in theDistrict of Columbia . Transmission Revenue. Under aFERC -approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the year endedDecember 31, 2020 compared to the same period in 2019 primary due to the settlement agreement of transmission-related income tax regulatory liabilities. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes. Other revenue decreased for the year endedDecember 31, 2020 compared to the same period in 2019, as Pepco temporarily suspended customer disconnections for non-payment beginning March of 2020 and temporarily ceased new late fees for all customers and restored services to customers upon request who were disconnected in the last twelve months. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation. The decrease of$63 million for the year endedDecember 31, 2020 compared to the same period in 2019, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs. 100
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Pepco
The changes in Operating and maintenance expense consisted of the following:
2020 vs. 2019
(Decrease) Increase
Change in environmental liabilities $ (22)
Expiration of lease arrangement
(15)
Pension and non-pension postretirement benefits expense (6)
BSC and PHISCO costs (4)
Storm related costs (2)
Credit loss expense(a) 8
Labor, other benefits, contracting, and materials 15
Other (1)
(27)
Regulatory required programs (2)
Total decrease $ (29)
__________
(a)Increased credit loss expense primarily as a result of suspending customer
disconnections, partially offset by the regulatory asset recorded in 2020
related to incremental credit loss expense due to COVID-19. See Note 3 -
Regulatory Matters of the Combined Notes to Consolidated Financial Statements
for additional information.
The changes in Depreciation and amortization expense consisted of the following:
2020 vs. 2019
Increase (Decrease)
Depreciation expense(a) $ 18
Regulatory asset amortization (2)
Regulatory required programs (13)
Total increase $ 3
__________
(a)Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Taxes other than income decreased for the year ended December 31, 2020 compared
to the same period in 2019, primarily due to lower taxes as part of regulatory
required programs that are fully offset within Operating revenues.
Interest expense, net increased for the year ended December 31, 2020 compared to
the same period in 2019, primarily due to issuance of debt in June 2019 ,
February 2020 , and June 2020 .
Gain on sales of assets for the year ended December 31, 2020 compared to the
year ended December 31, 2019 increased due the sale of land in the fourth
quarter of 2020.
Effective income tax rates were (2.7)% and 6.2% for the years ended December 31,
2020 and 2019, respectively. The change is primarily related to the settlement
agreement of ongoing transmission-related income tax regulatory liabilities. See
Note 3 - Regulatory Matters and Note 14 - Income Taxes of the Combined Notes to
Consolidated Financial Statements for additional information regarding the
components of the change in effective income tax rates.
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DPL
Results of Operations-DPL
(Unfavorable)
2020 2019 Favorable Variance
Operating revenues $ 1,271 $ 1,306 $ (35)
Operating expenses
Purchased power and fuel expense 503 526 23
Operating and maintenance 361 323 (38)
Depreciation and amortization 191 184 (7)
Taxes other than income taxes 65 56 (9)
Total operating expenses 1,120 1,089 (31)
Operating income 151 217 (66)
Other income and (deductions)
Interest expense, net (61) (61) -
Other, net 10 13 (3)
Total other income and (deductions) (51) (48) (3)
Income before income taxes 100 169 (69)
Income taxes (25) 22 47
Net income $ 125 $ 147 $ (22)
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 . Net
income decreased by $22 million primarily due to an increase in storm costs
related to the August 2020 storms in Delaware , an increase in credit loss
expense primarily as a result of suspending customer disconnections partially
offset by the regulatory asset recorded in 2020 related to incremental credit
loss expense due to COVID-19, unfavorable weather conditions in DPL's Delaware
electric service territory, and an increase in depreciation and amortization
expense, partially offset by higher electric distribution rates and an increase
in transmission rates (net of the impact of the settlement agreement of
transmission-related income tax regulatory liabilities).
The changes in Operating revenues consisted of the following:
2020 vs. 2019
(Decrease) Increase
Electric Gas Total
Weather $ (9) $ - $ (9)
Volume 2 (5) (3)
Distribution 12 4 16
Transmission (18) - (18)
Other 2 (1) 1
(11) (2) (13)
Regulatory required programs (17) (5) (22)
Total decrease $ (28) $ (7) $ (35)
Revenue Decoupling. The demand for electricity is affected by weather and
customer usage. However, Operating revenues from electric distribution in
Maryland are not impacted by abnormal weather or usage per customer as a result
of a bill stabilization adjustment (BSA) that provides for a fixed distribution
charge per customer by customer class. While Operating revenues from electric
distribution in Maryland are not impacted by abnormal weather or usage per
customer, they are impacted by changes in the number of customers.
Weather. The demand for electricity and natural gas in Delaware is affected by
weather conditions. With respect to the electric business, very warm weather in
summer months and, with respect to the electric and natural gas businesses, very
cold weather in winter months are referred to as "favorable weather conditions"
because these weather conditions result in increased deliveries of electricity
and natural gas. Conversely, mild weather reduces demand. During the year ended
December 31, 2020 compared to the same period in 2019, Operating revenues
related to weather decreased primarily due to unfavorable weather conditions in
DPL's Delaware service territory.
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DPL
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL'sDelaware electric service territory and a 30-year period in DPL'sDelaware natural gas service territory. The changes in heating and cooling degree days in DPL'sDelaware service territory for the year endedDecember 31, 2020 compared to same period in 2019 and normal weather consisted of the following: For the Years Ended December 31, % Change Delaware Electric Service Territory 2020 2019 Normal 2020 vs. 2019 2020 vs. Normal Heating Degree-Days 4,146 4,475 4,652 (7.4) % (10.9) % Cooling Degree-Days 1,264 1,476 1,239 (14.4) % 2.0 % For the Years Ended December 31, % Change Delaware Natural Gas Service Territory 2020 2019 Normal 2020 vs. 2019 2020 vs. Normal Heating Degree-Days 4,146 4,475 4,675 (7.4) % (11.3) %
Volume, exclusive of the effects of weather, remained relatively consistent for
the year ended
Weather -
Electric Retail Deliveries to Delaware Customers (in % Change Normal %
GWhs) 2020 2019 2020 vs. 2019 Change (b)
Residential 3,149 3,149 - % 4.8 %
Small commercial & industrial 1,255 1,320 (4.9) % (2.6) %
Large commercial & industrial 3,225 3,424 (5.8) % (4.8) %
Public authorities & electric railroads 32 34 (5.9) % (5.9) %
Total electric retail deliveries(a) 7,661 7,927 (3.4) % (0.7) %
As of December 31,
Number of Total Electric Customers (Maryland and Delaware) 2020 2019
Residential 472,621 468,162
Small commercial & industrial 62,461 61,721
Large commercial & industrial 1,223 1,411
Public authorities & electric railroads 609 613
Total 536,914 531,907
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from
DPL and customers purchasing electricity from a competitive electric generation
supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on
the historical 20-year average.
Natural Gas Retail Deliveries to Delaware Customers % Change Weather - Normal
(in mmcf) 2020 2019 2020 vs. 2019 % Change(b)
Residential 7,832 8,613 (9.1) % (2.5) %
Small commercial & industrial 3,718 4,287 (13.3) % (7.5) %
Large commercial & industrial 1,703 1,811 (6.0) % (6.0) %
Transportation 6,631 6,733 (1.5) % 0.2 %
Total natural gas deliveries(a) 19,884 21,444 (7.3) % (3.0) %
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DPL
As of December 31,
Number of Delaware Natural Gas Customers 2020 2019
Residential 127,128 125,873
Small commercial & industrial 10,017 9,999
Large commercial & industrial 16 17
Transportation 161 159
Total 137,322 136,048
__________
(a)Reflects delivery volumes 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.
(b)Reflects the change in delivery volumes assuming normalized weather based on
the historical 30-year average.
Distribution Revenue increased for the year ended December 31, 2020 compared to
the same period in 2019 primarily due to higher electric distribution rates in
Maryland that became effective in July 2020 , higher electric and natural gas
distribution rates in Delaware that became effective in the second half of 2020,
and the Distribution System Improvement Charge (DSIC) rate increases during
2020.
Transmission Revenue. Under a FERC -approved formula, transmission revenue varies
from year to year based upon fluctuations in the underlying costs, capital
investments being recovered, and the highest daily peak load, which is updated
annually in January based on the prior calendar years. Generally,
increases/decreases in the highest daily peak load will result in higher/lower
transmission revenue. Transmission revenue decreased for the year ended
December 31, 2020 compared to the same period in 2019 primarily due to the
settlement agreement of transmission-related income tax regulatory liabilities,
partially offset by higher fully recoverable costs. See Note 3 - Regulatory
Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
Other Revenue includes rental revenue, revenue related to late payment charges,
mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders
to recover costs incurred for regulatory programs such as energy efficiency
programs, DE Renewable Portfolio Standards, SOS procurement and administrative
costs, and GCR costs. The riders are designed to provide full and current cost
recovery as well as a return in certain instances. The costs of these programs
are included in Purchased power and fuel expense, Operating and maintenance
expense, Depreciation and amortization expense, and Taxes other than income
taxes. Customers have the choice to purchase electricity from competitive
electric generation suppliers. Customer choice programs do not impact the volume
of deliveries as DPL remains the distribution service provider for all customers
and charges a regulated rate for distribution service, which is recorded in
Operating revenues. For customers that choose to purchase electric generation or
natural gas from competitive suppliers, DPL acts as the billing agent and
therefore does not record Operating revenues or Purchased power and fuel expense
related to the electricity and/or natural gas. For customers that choose to
purchase electric generation or natural gas from DPL, DPL is permitted to
recover the electricity, natural gas, and REC procurement costs from customers
and therefore records the amounts related to the electricity, natural gas, and
RECs in Operating revenues and Purchased power and fuel expense. DPL recovers
electricity and REC procurement costs from customers with a slight mark-up and
natural gas costs without mark-up.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial
Statements for the presentation of DPL's revenue disaggregation.
The decrease of $23 million for the year ended December 31, 2020 compared to the
same period in 2019, in Purchased power and fuel expense is fully offset in
Operating revenues as part of regulatory required programs.
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DPL
The changes in Operating and maintenance expense consisted of the following:
2020 vs. 2019
Increase
(Decrease)
Storm-related costs $ 19
Labor, other benefits, contracting, and materials 14
Credit loss expense(a) 8
Pension and non-pension postretirement benefits expense (4)
BSC and PHISCO costs (1)
Other (1)
35
Regulatory required programs 3
Total increase $ 38
__________
(a)Increased credit loss expense primarily as a result of suspending customer
disconnections, partially offset by the regulatory asset recorded in 2020
related to incremental credit loss expense due to COVID-19. See Note 3 -
Regulatory Matters of the Combined Notes to Consolidated Financial Statements
for additional information.
The changes in Depreciation and amortization expense consisted of the following:
2020 vs. 2019
Increase
(Decrease)
Depreciation and amortization(a) $ 10
Regulatory asset amortization (1)
Regulatory required programs (2)
Total increase $ 7
__________
(a)Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Taxes other than income taxes increased for the year ended December 31, 2020
compared to the same period in 2019 primarily due to higher property taxes for
Maryland and Delaware .
Effective income tax rates were (25.0)% and 13.0% for the years ended
December 31, 2020 and 2019, respectively. The decrease for the year ended
December 31, 2020 is primarily related to the settlement agreement of
transmission-related income tax regulatory liabilities. See Note 3 - Regulatory
Matters and Note 14 - Income Taxes of the Combined Notes to Consolidated
Financial Statements for additional information regarding the components of the
change in effective income tax rates.
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ACE
Results of Operations-ACE
Favorable
2020 2019 (Unfavorable) Variance
Operating revenues $ 1,245 $ 1,240 $ 5
Operating expenses
Purchased power expense 609 608 (1)
Operating and maintenance 326 320 (6)
Depreciation and amortization 180 157 (23)
Taxes other than income taxes 8 4 (4)
Total operating expenses 1,123 1,089 (34)
Gain on sale of assets 2 - 2
Operating income 124 151 (27)
Other income and (deductions)
Interest expense, net (59) (58) (1)
Other, net 6 6 -
Total other income and (deductions) (53) (52) (1)
Income before income taxes 71 99 (28)
Income taxes (41) - 41
Net income $ 112 $ 99 $ 13
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 . Net
income increased $13 million primarily due to higher electric distribution rates
and an increase in transmission rates (net of the impact of the settlement
agreement of transmission-related income tax regulatory liabilities), partially
offset by an increase in depreciation and amortization expense and unfavorable
weather conditions in ACE's service territory.
The changes in Operating revenues consisted of the following:
2020 vs. 2019
(Decrease) Increase
Weather $ (8)
Volume (1)
Distribution 24
Transmission (19)
Other 3
(1)
Regulatory required programs 6
Total increase $ 5
Weather. The demand for electricity is affected by weather conditions. With
respect to the electric business, very warm weather in summer months and very
cold weather in winter months are referred to as "favorable weather conditions"
because these weather conditions result in increased deliveries of electricity.
Conversely, mild weather reduces demand. There was a decrease related to weather
for the year ended December 31, 2020 compared to the same period in 2019 due to
the impact of unfavorable weather conditions in ACE's service territory.
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ACE
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE's service territory. The changes in heating and cooling degree days in ACE's service territory for the year endedDecember 31, 2020 compared to same period in 2019, and normal weather consisted of the following: For the Years Ended December 31, % Change Heating and Cooling Degree-Days 2020 2019 Normal 2020 vs. 2019 2020 vs. Normal Heating Degree-Days 4,029 4,467 4,667 (9.8) % (13.7) % Cooling Degree-Days 1,314 1,374 1,174 (4.4) % 11.9 %
Volume, exclusive of the effects of weather, remained relatively consistent for
the year ended
% Change Weather - Normal %
Electric Retail Deliveries to Customers (in GWhs) 2020 2019 2020 vs. 2019 Change(b)
Residential 4,029 3,966 1.6 % 4.7 %
Small commercial & industrial 1,277 1,346 (5.1) % (4.0) %
Large commercial & industrial 3,067 3,429 (10.6) % (10.0) %
Public authorities & electric railroads 47 47 - % (0.2) %
Total retail deliveries(a) 8,420 8,788 (4.2) % (2.5) %
As of December 31,
Number of Electric Customers 2020 2019
Residential 497,672 494,596
Small commercial & industrial 61,622 61,497
Large commercial & industrial 3,282 3,392
Public authorities & electric railroads 701 679
Total 563,277 560,164
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. (b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average. Distribution Revenue increased for the year endedDecember 31, 2020 compared to the same period in 2019 primarily due to higher electric distribution rates that became effective inApril 2019 andApril 2020 . Transmission Revenue. Under aFERC -approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the year endedDecember 31, 2020 compared to the same period in 2019 primarily due to the settlement agreement for transmission-related income tax regulatory liabilities, partially offset by higher fully recoverable costs. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. 107
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ACE
Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation. The increase of$1 million for the year endedDecember 31, 2020 compared to same period in 2019, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs. The changes in Operating and maintenance expense consisted of the following: 2020 vs. 2019 Increase (Decrease) Labor, other benefits, contracting and materials $
6
Storm-related costs
3
Pension and non-pension postretirement benefits expense (1)
Other (2)
6
Regulatory required programs(a) -
Total increase $ 6
__________
(a)ACE is allowed to recover from or refund to customers the difference between
its annual credit loss expense and the amounts collected in rates annually
through the Societal Benefits Charge.
The changes in Depreciation and amortization expense consisted of the following:
2020 vs. 2019
Increase (Decrease)
Depreciation and amortization(a) $ 17
Regulatory asset amortization (2)
Regulatory required programs 8
Total increase $ 23
__________
(a)Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Gain on sale of assets for year ended December 31, 2020 compared to same period
in 2019 increased due to the sale of land in the first quarter of 2020.
Effective income tax rates were (57.7)% and 0.0% for the years ended
December 31, 2020 and 2019, respectively. The change is primarily related to the
settlement agreement of transmission-related income tax regulatory liabilities.
See Note 3 - Regulatory Matters and Note 14 - Income Taxes of the Combined Notes
to Consolidated Financial Statements for additional information regarding the
components of the change in effective income tax rates.
Liquidity and Capital Resources
All results included throughout the liquidity and capital resources section are
presented on a GAAP basis.
The Registrants' operating and capital expenditures requirements are provided by
internally generated cash flows from operations, the sale of certain
receivables, as well as funds from external sources in the capital markets and
through bank borrowings. The Registrants' businesses are capital intensive and
require considerable capital resources. Each of the Registrants annually
evaluates its financing plan, dividend practices,
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and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant's access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of$10.6 billion . As a result of disruptions in the commercial paper markets due to COVID-19 in March of 2020, Generation borrowed$1.5 billion on its revolving credit facility to refinance commercial paper. Generation repaid the$1.5 billion borrowed on the revolving credit facility onApril 3, 2020 using funds from short-term loans issued inMarch 2020 , cash proceeds from the sale of certain customer accounts receivable, and borrowings from the Exelon intercompany money pool. See Note 6 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sale of customer accounts receivable. See Executive Overview for additional information on COVID-19. The Registrants continue to utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the "Credit Matters" section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 17 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants' debt and credit agreements. Despite disruptions in the financial markets due to COVID-19, the Registrants issued long-term debt of$5.3 billion and were able to successfully complete their planned long-term debt issuances in 2020. NRC Minimum Funding Requirements (Exelon and Generation) NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant's owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 10 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation's share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. Within two years after shutting down a plant, Generation must submit a PSDAR to the NRC that includes the planned option for decommissioning the site. Upon retirement, Dresden will have adequate funding assurance, however, due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value,Byron may no longer meet the NRC minimum funding requirements and, as a result, the NRC may require additional financial assurance including possibly a parental guarantee from Exelon. Considering the different approaches to decommissioning available to Generation, the most likely estimates currently anticipated could require financial assurance for radiological decommissioning atByron of up to$90 million . 109
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Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an exemption in order for Generation to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs, if applicable). If a unit does not receive this exemption, those costs would be borne by Generation without reimbursement from or access to the NDT funds. Accordingly, based on current projections of the most likely decommissioning approach, it is expected that Dresden would not require supplemental cash from Generation, but some portion of theByron spent fuel management costs would need to be funded through supplemental cash from Generation. While the ultimate amounts may vary and could be offset by reimbursement of certain spent fuel management costs under theDOE settlement agreement, decommissioning forByron may require supplemental cash from Generation of up to$185 million , net of taxes, over a period of 10 years after permanent shutdown. As ofDecember 31, 2020 , Exelon would not be required to post a parental guarantee for TMI Unit 1 under the SAFSTOR scenario which is the planned decommissioning option as described in the TMI Unit 1 PSDAR filed by Generation with the NRC onApril 5, 2019 . OnOctober 16, 2019 , the NRC granted Generation's exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request would be required to allow the funds to be spent on site restoration costs, which are not expected to be incurred in the near term. Project Financing (Exelon and Generation) Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities. See Note 17 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt and credit facilities. Cash Flows from Operating Activities (All Registrants) Generation's cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation's future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers. The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. See Note 3 - Regulatory Matters and Note 19 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of regulatory and legal proceedings and proposed legislation. 110
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The following table provides a summary of the change in cash flows from operating activities for the years endedDecember 31, 2020 and 2019 by Registrant: (Decrease) increase in cash flows from operating activities Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Net income$ (1,074) $ (638) $ (250) $ (81) $ (11) $ 18 $ 23 $ (22) $ 13 Adjustments to reconcile net income to cash: Non-cash operating activities 273 328 156 (42) (33) (120) (123) 25 (3) Pension and non-pension postretirement benefit contributions (193) (80) (71) 10 (30) (14) 3 1 (1) Income taxes 204 (116) (87) 65 127 (41) (10) (37) (3) Changes in working capital and other noncurrent assets and liabilities (2,456) (2,633) (93) 74 79 42 96 11 (68) Option premiums paid, net (110) (110) - - - - - - - Collateral received (posted), net 932 960 (34) - 4 - - - -
(Decrease) increase in cash flows
$ (22) $ (62) from operating activities Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant's respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for 2020 and 2019 were as follows: •See Note 24 -Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on non-cash operating activity. •See Note 14 -Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on income taxes. •Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC markets. •During 2020, Exelon and Generation derecognized approximately$1.2 billion of accounts receivable. See Note 6 - Accounts Receivable for additional information on the sales of customer accounts receivable. Pension and Other Postretirement Benefits Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon's estimated annual qualified pension contributions will be approximately$500 million in 2021. Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements. While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon's management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans. 111
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The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2021:
Qualified Pension Plans Non-Qualified Pension Plans OPEB
Exelon $ 505 $ 51 $ 75
Generation 196 27 24
ComEd 170 2 23
PECO 14 1 -
BGE 57 1 16
PHI 29 9 7
Pepco 1 2 6
DPL - 1 -
ACE 3 - -
To the extent interest rates decline significantly or the pension and OPEB plans
earn less than the expected asset returns, annual pension contribution
requirements in future years could increase. Conversely, to the extent interest
rates increase significantly or the pension and OPEB plans earn greater than the
expected asset returns, annual pension and OPEB contribution requirements in
future years could decrease. Additionally, expected contributions could change
if Exelon changes its pension or OPEB funding strategy.
Cash Flows from Investing Activities (All Registrants)
The following table provides a summary of the change in cash flows from
investing activities for the years ended December 31, 2020 and 2019 by
Registrant:
Increase (decrease) in cash
flows from investing
activities Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Capital expenditures $ (800) $ 98 $ (302) $ (208) $ (102) $ (249) $ (147) $ (76) $ (26)
Proceeds from NDT fund sales,
net (87) (87) - - - - - - -
Acquisitions of assets and
businesses, net 41 41 - - - - - - -
Proceeds from sales of assets
and businesses (7) (6) - - - - - - -
Changes in intercompany money
pool - - - 136 - - - - -
Collection of DPP 3,771 3,771 - - - - - - -
Other investing activities 6 8 (27) 8 (6) 10 (3) (4) 7
Increase (decrease) in cash
flows from investing $ 2,924 $ 3,825 $ (329) $ (64) $ (108) $ (239) $ (150) $ (80) $ (19)
activities
Significant investing cash flow impacts for the Registrants for 2020 and 2019
were as follows:
•Variances in capital expenditures are primarily due to the timing of cash
expenditures for capital projects. Refer below for additional information on
projected capital expenditure spending.
•Changes in intercompany money pool are driven by short-term borrowing needs.
Refer to more information regarding the intercompany money pool below.
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Capital Expenditure Spending The Registrants most recent estimates of capital expenditures for plant additions and improvements for 2021 are approximately as follows:
(in millions) Transmission Distribution Gas Total
Exelon N/A N/A N/A $ 7,775
Generation N/A N/A N/A 1,150
ComEd 475 1,925 N/A 2,400
PECO 175 750 350 1,275
BGE 325 450 425 1,200
PHI 525 1,100 75 1,700
Pepco 250 675 N/A 925
DPL 125 225 75 425
ACE 150 200 N/A 350
Projected capital expenditures and other investments are subject to periodic
review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 48% of projected 2021 capital expenditures at Generation are for
the acquisition of nuclear fuel, with the remaining amounts primarily reflecting
additions and upgrades to existing generation facilities (including material
condition improvements during nuclear refueling outages). Generation anticipates
that it will fund capital expenditures with internally generated funds and
borrowings.
Utility Registrants
Projected 2021 capital expenditures at the Utility Registrants are for
continuing projects to maintain and improve operations, including enhancing
reliability and adding capacity to the transmission and distribution systems
such as the Utility Registrants' construction commitments under PJM's RTEP.
The Utility Registrants as transmission owners are subject to NERC compliance
requirements. NERC provides guidance to transmission owners regarding
assessments of transmission lines. The results of these assessments could
require the Utility Registrants to incur incremental capital or operating and
maintenance expenditures to ensure their transmission lines meet NERC standards.
In 2010, NERC provided guidance to transmission owners that recommended the
Utility Registrants perform assessments of their transmission lines. ComEd,
PECO, and BGE submitted their final bi-annual reports to NERC in January 2014 .
PECO will be incurring incremental capital expenditures associated with this
guidance following the completion of the assessments. Specific projects and
expenditures are identified as the assessments are completed. PECO's forecasted
2021 capital expenditures above reflect capital spending for remediation to be
completed through 2021. ComEd, BGE, Pepco, DPL, and ACE are complete with their
assessments and do not expect capital expenditures related to this guidance in
2021.
The Utility Registrants anticipate that they will fund their capital
expenditures with a combination of internally generated funds and borrowings and
additional capital contributions from parent.
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Cash Flows from Financing Activities (All Registrants) The following tables provides a summary of the change in cash flows from financing activities for the years endedDecember 31, 2020 and 2019 by Registrant: Increase (decrease) in cash flows from financing activities Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Changes in short-term borrowings, net$ 5 $ 200 $ 63 $ -$ (116) $ 131 $ (89) $ 34 $ 186 Long-term debt, net 403 (958) 100 25 - 146 162 35 (53) Changes in intercompany money pool - 385 - 40 - (3) - - - Dividends paid on common stock (84) - 9 18 (22) - (19) (2) 10 Distributions to member - (835) - - - (27) - - - Contributions from parent/member - 23 462 60 218 96 102 49 (58) Other financing activities (121) (19) 3 2 - (5) (3) (1) -
Increase (decrease) in cash
$ 85 flows from financing activities Significant financing cash flow impacts for the Registrants for 2020 and 2019 were as follows: •Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 17 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings. •Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for additional information. •Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below. •Exelon's ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 19 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared. •For the years endedDecember 31, 2020 and 2019, other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the Registrants' debt issuances. 114
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Debt Issuances and Redemptions
See Note 17 - Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements for additional information of the Registrants' long-term
debt. Debt activity for 2020 and 2019 by Registrant was as follows:
During 2020, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon Notes 4.05 % April 15, 2030 $ 1,250 Repay existing indebtedness
and for general corporate
purposes.
Exelon Notes 4.70 % April 15, 2050 750 Repay existing indebtedness
and for general corporate
purposes.
Generation Senior Notes 3.25 % June 1, 2025 900 Repay existing indebtedness
and for general corporate
purposes.
Generation EGR IV Nonrecourse Debt(a) LIBOR + 2.75% December 15, 2027 750 Repay existing indebtedness
and for general corporate
purposes.
Generation Energy Efficiency Project 3.95 % February 28, 2021 3 Funding to install energy
Financing(b) conservation measures for the
Fort Meade project.
Generation Energy Efficiency Project 2.53 % March 31, 2021 3 Funding to install energy
Financing(b) conservation measures for the
Fort AP Hill project.
ComEd First Mortgage Bonds, 2.20 % March 1, 2030 350 Repay a portion of outstanding
Series 128 commercial paper obligations
and fund other general
corporate purposes.
ComEd First Mortgage Bonds, 3.00 % March 1, 2050 650 Repay a portion of outstanding
Series 129 commercial paper obligations
and fund other general
corporate purposes.
PECO First and Refunding 2.80 % June 15, 2050 350 Funding for general corporate
Mortgage Bonds purposes.
BGE Senior Notes 2.90 % June 15, 2050 400 Repay commercial paper
obligations and for general
corporate purposes.
Pepco First Mortgage Bonds 2.53 % February 25, 2030 150 Repay existing indebtedness
and for general corporate
purposes.
Pepco First Mortgage Bonds 3.28 % September 23, 2050 150 Repay existing indebtedness
and for general corporate
purposes.
DPL First Mortgage Bonds 2.53 % June 9, 2030 100 Repay existing indebtedness
and for general corporate
purposes.
DPL Tax-Exempt Bonds(c) 1.05 % January 1, 2031 78 Refinance existing
indebtedness.
ACE Tax-Exempt First Mortgage 2.25 % June 1, 2029 23 Refinance existing
Bonds indebtedness.
ACE First Mortgage Bonds 3.24 % June 9, 2050 100 Repay existing
indebtedness
and for general corporate
purposes.
__________
(a)See Note 17 - Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements for additional information of nonrecourse
debt.
(b)For Energy Efficiency Project Financing, the maturity dates represent the
expected date of project completion, upon which the respective customer assumes
the outstanding debt.
(c)The bonds have a 1.05% interest rate through July 2025 .
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During 2019, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds
Generation Energy Efficiency 3.95 % February 28, 2021 $ 4 Funding to install energy
Project Financing(a) conservation measures for the
Fort Meade project.
Generation Energy Efficiency 3.46 % February 28, 2021 39 Funding to install energy
Project Financing(a) conservation measures for the
Marine Corps. Logistics
Project.
Generation Energy Efficiency 2.53 % March 31, 2021 2 Funding to install energy
Project Financing(a) conservation measures for the
Fort AP Hill project.
ComEd First Mortgage 4.00 % March 1, 2049 400 Repay a portion of ComEd's
Bonds, Series 126 outstanding commercial paper
obligations and fund other
general corporate purposes.
ComEd First Mortgage 3.20 % November 15, 2049 300 Repay a portion of ComEd's
Bonds, Series 127 outstanding commercial paper
obligations and fund other
general corporate purposes.
PECO First and Refunding 3.00 % September 15, 2049 325 Repay short-term borrowings
Mortgage Bonds and for general corporate
purposes.
BGE Senior Notes 3.20 % September 15, 2049 400 Repay commercial paper
obligations and for general
corporate purposes.
Pepco First Mortgage Bonds 3.45 % June 13, 2029 150 Repay existing indebtedness
and for general corporate
purposes.
Pepco Unsecured Tax-Exempt 1.70 % September 1, 2022 110 Refinance existing
Bonds indebtedness.
DPL First Mortgage Bonds 4.14 % December 12, 2049 75 Repay existing indebtedness
and for general corporate
purposes.
ACE First Mortgage Bonds 3.50 % May 21, 2029 100 Repay existing indebtedness
and for general corporate
purposes.
ACE First Mortgage Bonds 4.14 % May 21, 2049 50 Repay existing indebtedness
and for general corporate
purposes.
__________
(a)For Energy Efficiency Project Financing, the maturity dates represent the
expected date of project completion, upon which the respective customer assumes
the outstanding debt.
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During 2020, the following long-term debt was retired and/or redeemed:
Company Type Interest Rate Maturity Amount
Exelon Notes 2.85% June 15, 2020 $ 900
Long-Term Software License
Exelon Agreement 3.95% May 1, 2024 24
Generation Senior Notes 2.95% January 15, 2020 1,000
Generation Senior Notes 4.00% October 1, 2020 550
Generation Senior Notes(a) 5.15% December 1, 2020 550
December 1, 2025 - June
Generation Tax-Exempt Bonds 2.50% - 2.70% 1, 2036 412
Generation EGR IV Nonrecourse Debt(b) 3 month LIBOR + 3.00% November 30, 2024 796
Continental Wind Nonrecourse
Generation Debt(b) 6.00% February 28, 2033 33
Antelope Valley DOE Nonrecourse
Generation Debt(b) 2.29% - 3.56% January 5, 2037 23
Generation RPG Nonrecourse Debt(b) 4.11% March 31, 2035 9
Generation Energy Efficiency Project Financing 3.71% December 31, 2020 4
Generation NUKEM 3.15% September 30, 2020 3
Generation SolGen Nonrecourse Debt 3.93% September 30, 2036 3
Generation Energy Efficiency Project Financing 4.12% November 30, 2020 1
ComEd First Mortgage Bonds 4.00% August 1, 2020 500
DPL Tax-Exempt Bonds 5.40% February 1, 2031 78
ACE Tax-Exempt First Mortgage Bonds 4.88% June 1, 2029 23
ACE Transition Bonds 5.55% October 20, 2023 20
__________
(a)The senior notes are legacy Constellation mirror debt that were previously
held at Exelon and Generation. As part of the 2012 Constellation merger, Exelon
and Generation assumed intercompany loan agreements that mirrored the terms and
amounts of external obligations held by Exelon, resulting in intercompany notes
payable at Generation.
(b)See Note 17 - Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements for additional information of nonrecourse
debt.
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During 2019, the following long-term debt was retired and/or redeemed:
Company Type Interest Rate Maturity Amount
Long-Term Software License
Exelon Agreement 3.95% May 1, 2024 $ 18
Antelope Valley DOE Nonrecourse
Generation Debt(a) 2.33% - 3.56% January 5, 2037 23
Generation Kennett Square Capital Lease 7.83% September 20, 2020 5
Continental Wind Nonrecourse
Generation Debt(a) 6.00% February 28, 2033 32
Generation Pollution control notes 2.50% March 1, 2019 23
Generation RPG Nonrecourse Debt(a) 4.11% March 31, 2035 10
Generation Energy Efficiency Project Financing 3.46% April 30, 2019 39
Generation EGR IV Nonrecourse Debt(a) 3 month LIBOR + 3.00% November 30, 2024 38
Generation Hannie Mae, LLC Defense Financing 4.12% November 30, 2019 1
Generation Energy Efficiency Project Financing 3.72% July 31, 2019 25
Generation NUKEM 3.15% September 30, 2020 36
Generation SolGen Nonrecourse Debt(a) 3.93% September 30, 2036 6
Generation Energy Efficiency Project Financing 4.17% October 31, 2019 1
Generation Energy Efficiency Project Financing 3.53% March 31, 2020 1
Generation Energy Efficiency Project Financing 4.26% September 30, 2019 1
Generation Senior Notes 5.20% October 1, 2019 600
Generation Dominion Federal Corp 3.17% October 31, 2019 18
Generation Fort Detrick Project Financing 3.55% October 31, 2019 1
ComEd First Mortgage Bonds 2.15% January 15, 2019 300
Pepco Secured Tax-Exempt Bonds 6.20% - 7.49% 2021 - 2022 110
DPL Medium Term Notes, Unsecured 7.61% December 2, 2019 12
ACE Transition Bonds 5.55% October 20, 2023 18
__________
(a)See Note 17 - Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements for additional information of nonrecourse
debt.
From time to time and as market conditions warrant, the Registrants may engage
in long-term debt retirements via tender offers, open market repurchases or
other viable options to reduce debt on their respective balance sheets.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the year
ended December 31, 2020 and for the first quarter of 2021 were as follows:
Cash per
Period Declaration Date Shareholder of Record Date Dividend Payable Date Share(a)
First Quarter 2020 January 28, 2020 February 20, 2020 March 10, 2020 $
0.3825
Second Quarter 2020 April 28, 2020 May 15, 2020 June 10, 2020 $
0.3825
Third Quarter 2020 July 28, 2020 August 14, 2020 September 10, 2020 $
0.3825
Fourth Quarter 2020 November 2, 2020 November 16, 2020 December 10, 2020 $
0.3825
First Quarter 2021 February 21, 2021 March 8, 2021 March 15, 2021 $ 0.3825
___________
(a)Exelon's Board of Directors approved an updated dividend policy for 2021. The
2021 quarterly dividend will remain the same as the 2020 dividend of $0.3825 per
share.
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Credit Matters (All Registrants)
The Registrants fund liquidity needs for capital investment, working capital,
energy hedging, and other financial commitments through cash flows from
continuing operations, public debt offerings, commercial paper markets, and
large, diversified credit facilities. The credit facilities include $10.6
billion in aggregate total commitments of which $7.7 billion was available to
support additional commercial paper as of December 31, 2020, and of which no
financial institution has more than 7% of the aggregate commitments for the
Registrants. The Registrants had access to the commercial paper markets and had
availability under their revolving credit facilities during 2020 to fund their
short-term liquidity needs, when necessary. The Registrants routinely review the
sufficiency of their liquidity position, including appropriate sizing of credit
facility commitments, by performing various stress test scenarios, such as
commodity price movements, increases in margin-related transactions, changes in
hedging levels, and the impacts of hypothetical credit downgrades. The
Registrants have continued to closely monitor events in the financial markets
and the financial institutions associated with the credit facilities, including
monitoring credit ratings and outlooks, credit default swap levels, capital
raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS for additional
information regarding the effects of uncertainty in the capital and credit
markets.
The Registrants believe their cash flow from operating activities, access to
credit markets, and their credit facilities provide sufficient liquidity. If
Generation lost its investment grade credit rating as of December 31, 2020, it
would have been required to provide incremental collateral of approximately
$1.5 billion to meet collateral obligations for derivatives, non-derivatives,
normal purchases and normal sales contracts, and applicable payables and
receivables, net of the contractual right of offset under master netting
agreements, which is well within the $4.7 billion of available credit capacity
of its revolver.
The following table presents the incremental collateral that each Utility
Registrant would have been required to provide in the event each Utility
Registrant lost its investment grade credit rating at December 31, 2020 and
available credit facility capacity prior to any incremental collateral at
December 31, 2020:
Available Credit
Facility Capacity
Other Incremental Prior to Any
PJM Credit Policy Collateral Incremental
Collateral Required(a) Collateral
ComEd $ 13 $ - $ 675
PECO 2 34 600
BGE 10 54 600
Pepco 8 - 264
DPL 4 9 154
ACE - - 113
__________
(a)Represents incremental collateral related to natural gas procurement
contracts.
Exelon Credit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements
primarily through the issuance of commercial paper. Generation and PECO meet
their short-term liquidity requirements primarily through the issuance of
commercial paper and borrowings from the Exelon intercompany money pool. Pepco,
DPL, and ACE meet their short-term liquidity requirements primarily through the
issuance of commercial paper and borrowings from the PHI intercompany money
pool. PHI Corporate meets its short-term liquidity requirements primarily
through the issuance of short-term notes and the Exelon intercompany money pool.
The Registrants may use their respective credit facilities for general corporate
purposes, including meeting short-term funding requirements and the issuance of
letters of credit.
See Note 17 - Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements for additional information of the Registrants' credit
facilities and short term borrowing activity.
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Capital Structure
At December 31, 2020, the capital structures of the Registrants consisted of the
following:
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Long-term debt 50 % 27 % 43 % 44 % 47 % 40 % 49 % 48 % 47 %
Long-term debt to
affiliates(a) 1 % 1 % 1 % 2 % - % - % - % - % - %
Common equity 46 % - % 54 % 54 % 53 % - % 50 % 48 % 47 %
Member's equity - % 68 % - % - % - % 58 % - % - % - %
Commercial paper and
notes payable 3 % 4 % 2 % - % - % 2 % 1 % 4 % 6 %
__________
(a)Includes approximately $390 million, $205 million, and $184 million owed to
unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special
purpose entities were created for the sole purposes of issuing mandatorily
redeemable trust preferred securities of ComEd and PECO. See Note 23 - Variable
Interest Entities of the Combined Notes to Consolidated Financial Statements for
additional information regarding the authoritative guidance for VIEs.
Security Ratings
The Registrants' access to the capital markets, including the commercial paper
market, and their respective financing costs in those markets, may depend on the
securities ratings of the entity that is accessing the capital markets.
The Registrants' borrowings are not subject to default or prepayment as a result
of a downgrading of securities, although such a downgrading of a Registrant's
securities could increase fees and interest charges under that Registrant's
credit agreements.
As part of the normal course of business, the Registrants enter into contracts
that contain express provisions or otherwise permit the Registrants and their
counterparties to demand adequate assurance of future performance when there are
reasonable grounds for doing so. In accordance with the contracts and applicable
contracts law, if the Registrants are downgraded by a credit rating agency, it
is possible that a counterparty would attempt to rely on such a downgrade as a
basis for making a demand for adequate assurance of future performance, which
could include the posting of collateral. See Note 16 - Derivative Financial
Instruments of the Combined Notes to Consolidated Financial Statements for
additional information on collateral provisions.
The credit ratings for Exelon Corporate, PECO, BGE, PHI, Pepco, DPL, and ACE did
not change for the twelve months ended December 31, 2020. On November 4, 2020,
S&P revised its assessment of the strategic relationship between Exelon and
Generation and subsequently lowered Generation's senior unsecured debt rating to
'BBB' from 'BBB+'. On July 21, 2020, S&P lowered ComEd's long-term issuer credit
rating from 'A-' to a 'BBB+'. S&P also affirmed the current 'A' rating on
ComEd's senior secured debt and 'A-2' short-term rating, which influences long
and short-term borrowing cost.
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Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more
favorable to the borrowing participants than the cost of external financing,
both Exelon and PHI operate an intercompany money pool. Maximum amounts
contributed to and borrowed from the money pool by participant and the net
contribution or borrowing as of December 31, 2020, are presented in the
following tables:
As of December 31,
For the Year Ended December 31, 2020 2020
Maximum Maximum Contributed
Exelon Intercompany Money Pool Contributed Borrowed (Borrowed)
Exelon Corporate $ 1,364 $ - $ 598
Generation 254 (980) (285)
PECO 292 (40) (40)
BSC 25 (563) (312)
PHI Corporate - (22) (21)
PCI 60 - 60
For the Year Ended December 31, 2020 As of December 31, 2020
Maximum Maximum
PHI Intercompany Money Pool Contributed Borrowed Contributed (Borrowed)
Pepco $ 166 $ (57) $ -
DPL 62 (95) -
ACE - (133) -
Shelf Registration Statements
Exelon, Generation , and the Utility Registrants have a currently effective
combined shelf registration statement unlimited in amount, filed with the SEC ,
that will expire in August 2022. The ability of each Registrant to sell
securities off the shelf registration statement or to access the private
placement markets will depend on a number of factors at the time of the proposed
sale, including other required regulatory approvals, as applicable, the current
financial condition of the Registrant, its securities ratings and market
conditions.
Regulatory Authorizations
The Utility Registrants are required to obtain short-term and long-term
financing authority from Federal and State Commissions as follows:
As of December 31, 2020
Short-term Financing Authority(a) Long-term Financing Authority(a)
Commission Expiration Date Amount Commission Expiration Date Amount
ComEd(b) FERC December 31, 2021 $ 2,500 ICC February 1, 2023 $ 893
PECO FERC December 31, 2021 1,500 PAPUC December 31, 2021 1,225
BGE FERC December 31, 2021 700 MDPSC N/A 1,100
Pepco FERC December 31, 2021 500 MDPSC / DCPSC December 31, 2022 900
DPL FERC December 31, 2021 500 MDPSC / DPSC December 31, 2022 297
ACE(c) NJBPU December 31, 2021 350 NJBPU December 31, 2022 600
__________
(a)Generation currently has blanket financing authority it received from FERC in
connection with its market-based rate authority.
(b)As of December 31, 2020, ComEd had $893 million in new money long-term debt
financing authority from the ICC with an expiration date of February 1, 2023. On
January 20, 2021, ComEd received $350 million of long-term debt refinancing
authority from the ICC approved with an effective date of February 1, 2021 and
an expiration date of February 1, 2024.
(c)On December 2, 2020, ACE received approval from the NJBPU for $600 million in
new long-term debt financing authority with an effective date of January 1,
2021.
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Contractual Obligations and Off-Balance Sheet Arrangements
The following tables summarize the Registrants' future estimated cash payments
as of December 31, 2020 under existing contractual obligations, including
payments due by period.
Exelon
Payment due within
2022 - 2024 - 2026
Total 2021 2023 2025 and beyond
Long-term debt(a) $ 36,839 $ 1,809 $ 3,933 $ 3,012 $ 28,085
Interest payments on long-term debt(b) 24,486 1,468 2,766 2,592 17,660
Operating leases(c) 1,213 141 224 193 655
Purchase power obligations(d) 1,613 512 823 264 14
Fuel purchase agreements(e) 5,667 1,183 1,584 1,237 1,663
Electric supply procurement 3,170 1,909 1,253 8 -
Long-term renewable energy and REC
commitments 2,238 301 548 437 952
Other purchase obligations(f) 9,374 6,673 1,492 440 769
DC PLUG obligation 100 30 60 10 -
SNF obligation 1,208 - - - 1,208
Pension contributions(g) 3,030 505 1,010 1,010 505
Total contractual obligations $ 88,938 $ 14,531 $ 13,693 $ 9,203 $ 51,511
__________
(a)Includes amounts from ComEd and PECO financing trusts.
(b)Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2020 and do not reflect anticipated
future refinancing, early redemptions, or debt issuances. Variable rate interest
obligations are estimated based on rates as of December 31, 2020. Includes
estimated interest payments due to ComEd and PECO financing trusts.
(c)Capacity payments associated with contracted generation lease agreements are
net of sublease and capacity offsets of $98 million, $55 million, $44 million,
$44 million, $44 million, and $179 million for 2021, 2022, 2023, 2024, 2025, and
thereafter, respectively and $464 million in total.
(d)Purchase power obligations primarily include expected payments for REC
purchases and payments associated with contracted generation agreements, which
may be reduced based on plant availability. Expected payments exclude payments
on renewable generation contracts that are contingent in nature.
(e)Represents commitments to purchase nuclear fuel, natural gas and related
transportation, storage capacity, and services, including those related to CENG.
(f)Represents the future estimated value at December 31, 2020 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between the Registrants and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
(g)These amounts represent Exelon's expected contributions to its qualified
pension plans. Qualified pension contributions for years after 2026 are not
included.
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Generation
Payment due within
2022 - 2024 - 2026
Total 2021 2023 2025 and beyond
Long-term debt $ 6,066 $ 195 $ 1,024 $ 900 $ 3,947 Interest payments on long-term debt(a) 3,536 270 474 443
2,349
Operating leases(b) 731 47 114 109 461
Purchase power obligations(c) 1,613 512 823 264 14
Fuel purchase agreements(d) 4,450 928 1,207 1,022 1,293
Other purchase obligations(e) 2,286 1,208 231 155 692
SNF obligation 1,208 - - - 1,208
Total contractual obligations $ 19,890 $ 3,160 $ 3,873 $ 2,893 $ 9,964
__________
(a)Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2020 and do not reflect anticipated
future refinancing, early redemptions, or debt issuances. Variable rate interest
obligations are estimated based on rates as of December 31, 2020.
(b)Capacity payments associated with contracted generation lease agreements are
net of sublease and capacity offsets of $98 million, $55 million, $44 million,
$44 million, $44 million, and $179 million for 2021, 2022, 2023, 2024, 2025, and
thereafter, respectively and $464 million in total.
(c)Purchase power obligations primarily include expected payments for REC
purchases and capacity payments associated with contracted generation
agreements, which may be reduced based on plant availability. Expected payments
exclude payments on renewable generation contracts that are contingent in
nature.
(d)Represents commitments to purchase nuclear fuel, natural gas and related
transportation, storage capacity, and services, including those related to CENG.
(e)Represents the future estimated value at December 31, 2020 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between Generation and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
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ComEd
Payment due within
2022 - 2024 - 2026
Total 2021 2023 2025 and beyond
Long-term debt(a) $ 9,284 $ 350 $ - $ 250 $ 8,684
Interest payments on long-term debt(b) 7,207 360 720 711 5,416
Operating leases 8 3 3 2 -
Electric supply procurement 600 388 212 - -
Long-term renewable energy and REC
commitments 1,953 269 485 384 815
Other purchase obligations(c) 1,524 1,397 74 35 18
ZEC commitments 1,127 176 351 351 249
Total contractual obligations $ 21,703 $ 2,943 $ 1,845 $ 1,733 $ 15,182
__________
(a)Includes amounts from ComEd financing trust.
(b)Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2020 and do not reflect anticipated
future refinancing, early redemptions, or debt issuances. Includes estimated
interest payments due to the ComEd financing trust.
(c)Represents the future estimated value at December 31, 2020 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between ComEd and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
PECO
Payment due within
2022 - 2024 - 2026
Total 2021 2023 2025 and beyond
Long-term debt(a) $ 3,984 $ 300 $ 400 $ 350 $ 2,934
Interest payments on long-term debt(b) 2,867 146 280 271
2,170
Operating leases 1 1 - - -
Fuel purchase agreements(c) 405 138 183 41 43
Electric supply procurement 536 431 105 - -
Other purchase obligations(d) 898 813 66 19 -
Total contractual obligations $ 8,691 $ 1,829 $ 1,034 $ 681 $ 5,147
__________
(a)Includes amounts from PECO financing trusts.
(b)Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2020 and do not reflect anticipated
future refinancing, early redemptions, or debt issuances. Includes estimated
interest payments due to the PECO financing trusts.
(c)Represents commitments to purchase natural gas and related transportation,
storage capacity, and services.
(d)Represents the future estimated value at December 31, 2020 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between PECO and third-parties for the provision of services and materials,
entered into in the normal course of business not specifically reflected
elsewhere in this table. These estimates are subject to significant variability
from period to period.
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BGE
Payment due within
2022 - 2024 - 2026
Total 2021 2023 2025 and beyond
Long-term debt $ 3,700 $ 300 $ 550 $ - $ 2,850
Interest payments on long-term debt(a) 2,450 127 240 220
1,863
Operating leases 81 46 17 - 18
Fuel purchase agreements(b) 517 84 128 109 196
Electric supply procurement 1,088 665 423 - -
Other purchase obligations(c) 1,372 976 364 26 6
Total contractual obligations $ 9,208 $ 2,198 $ 1,722 $ 355 $ 4,933
__________
(a)Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2020 and do not reflect anticipated
future refinancing, early redemptions, or debt issuances.
(b)Represents commitments to purchase natural gas and related transportation,
storage capacity, and services.
(c)Represents the future estimated value at December 31, 2020 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between BGE and third-parties for the provision of services and materials,
entered into in the normal course of business not specifically reflected
elsewhere in this table. These estimates are subject to significant variability
from period to period.
PHI
Payment due within
2022 - 2024 - 2026
Total 2021 2023 2025 and beyond
Long-term debt $ 6,443 $ 339 $ 809 $ 700 $ 4,595
Interest payments on long-term debt(a) 4,135 266 517 447 2,905
Finance leases 53 8 16 16 13
Operating leases 306 40 77 69 120
Fuel purchase agreements(b) 295 33 66 65 131
Electric supply procurement 1,791 1,051 732 8 -
Long-term renewable energy and REC
commitments 285 32 63 53 137
Other purchase obligations(c) 1,767 1,362 341 48 16
DC PLUG obligation 100 30 60 10 -
Total contractual obligations $ 15,175 $ 3,161 $ 2,681 $ 1,416 $ 7,917
__________
(a)Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2020 and do not reflect anticipated
future refinancing, early redemptions, or debt issuances. Variable rate interest
obligations are estimated based on rates as of December 31, 2020.
(b)Represents commitments to purchase natural gas and related transportation,
storage capacity, and services.
(c)Represents the future estimated value at December 31, 2020 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of
services and materials, entered into in the normal course of business not
specifically reflected elsewhere in this table. These estimates are subject to
significant variability from period to period.
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Pepco
Payment due within
2022 - 2024 - 2026
Total 2021 2023 2025 and beyond
Long-term debt $ 3,185 $ - $ 309 $ 400 $ 2,476
Interest payments on long-term debt(a) 2,429 147 281 251 1,750 Finance leases 18 3 6 6 3 Operating leases 63 8 15 12 28 Electric supply procurement 754 432 314 8 - Other purchase obligations(b) 1,034 748 243 32 11 DC PLUG obligation 100 30 60 10 - Total contractual obligations $ 7,583 $ 1,368 $
1,228 $ 719 $ 4,268
__________
(a)Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2020 and do not reflect anticipated
future refinancing, early redemptions, or debt issuances.
(b)Represents the future estimated value at December 31, 2020 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between Pepco and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
DPL
Payment due within
2022 - 2024 - 2026
Total 2021 2023 2025 and beyond
Long-term debt $ 1,666 $ 79 $ 500 $ - $ 1,087
Interest payments on long-term debt(a) 1,016 59 116 82 759
Finance leases 21 3 6 6 6
Operating leases 80 11 19 15 35
Fuel purchase agreements(b) 295 33 66 65 131
Electric supply procurement 469 290 179 - -
Long-term renewable energy and
associated REC commitments 285 32 63 53 137
Other purchase obligations(c) 419 349 63 7 -
Total contractual obligations $ 4,251 $ 856 $ 1,012 $ 228 $ 2,155
__________
(a)Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2020 and do not reflect anticipated
future refinancing, early redemptions, or debt issuances. Variable rate interest
obligations are estimated based on rates as of December 31, 2020.
(b)Represents commitments to purchase natural gas and related transportation,
storage capacity, and services.
(c)Represents the future estimated value at December 31, 2020 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between DPL and third-parties for the provision of services and materials,
entered into in the normal course of business not specifically reflected
elsewhere in this table. These estimates are subject to significant variability
from period to period.
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ACE
Payment due within
2022 - 2024 - 2026
Total 2021 2023 2025 and beyond
Long-term debt $ 1,407 $ 259 $ - $ 300 $ 848
Interest payments on long-term debt (a) 527 46 92 86 303
Finance leases 14 2 4 4 4
Operating leases 16 5 7 4 -
Electric supply procurement 568 329 239 - -
Other purchase obligations(b) 267 236 25 6 -
Total contractual obligations $ 2,799 $ 877 $ 367 $ 400 $ 1,155
__________
(a)Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2020 and do not reflect anticipated
future refinancing, early redemptions, or debt issuances.
(b)Represents the future estimated value at December 31, 2020 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between ACE and third-parties for the provision of services and materials,
entered into in the normal course of business not specifically reflected
elsewhere in this table. These estimates are subject to significant variability
from period to period.
See Note 19 - Commitments and Contingencies and Note 3 - Regulatory Matters of
the Combined Notes to Consolidated Financial Statements for additional
information of the Registrants' other commitments potentially triggered by
future events. Additionally, see below for where to find additional information
regarding certain contractual obligations in the Combined Notes to the
Consolidated Financial Statements:
Location within Notes to the Consolidated Financial
Item Statements
Long-term debt Note 17 - Debt and Credit Agreements
Interest payments on long-term debt Note 17 - Debt and Credit Agreements
Finance leases Note 11 - Leases
Operating leases Note 11 - Leases
SNF obligation Note 19 - Commitments and Contingencies
REC commitments Note 3 - Regulatory Matters
ZEC commitments Note 3 - Regulatory Matters
DC PLUG obligation Note 3 - Regulatory Matters
Pension contributions Note 15 - Retirement Benefits
Sales of Customer Accounts Receivable
On April 8, 2020, Generation entered into an accounts receivable financing
facility with a number of financial institutions and a commercial paper conduit
to sell certain receivables, which expires on April 7, 2021 unless renewed by
the mutual consent of the parties in accordance with its terms. The facility
allows Generation to obtain financing at lower cost and diversify its sources of
liquidity. See Note 6 - Accounts Receivable of the Combined Notes to
Consolidated Financial Statements for additional information.
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