COMMONWEALTH EDISON COMPANY (Dollars in millions except per share data, unless otherwise noted) 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 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. Financial Results of Operations GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income (Loss) attributable to common shareholders by Registrant for the three months endedMarch 31, 2021 compared to the same period in 2020. For additional information regarding the financial results for the three months endedMarch 31, 2021 and 2020 see the discussions of Results of Operations by Registrant. Three Months Ended Favorable March 31, (unfavorable) 2021 2020 variance Exelon$ (289) $ 582$ (871) Generation (793) 45 (838) ComEd 197 168 29 PECO 167 140 27 BGE 209 181 28 PHI 128 108 20 Pepco 59 52 7 DPL 56 45 11 ACE 14 13 1 Other(a) (197) (60) (137) __________ (a)Primarily includes eliminating and consolidating adjustments, Exelon's corporate operations, shared service entities and other financing and investing activities. Three Months EndedMarch 31, 2021 Compared to Three Months EndedMarch 31, 2020 . Net income attributable to common shareholders decreased by$871 million and diluted loss per average common share decreased to$(0.30) in 2021 from$0.60 in 2020 primarily due to: •Impacts of theFebruary 2021 extreme cold weather event; 121 -------------------------------------------------------------------------------- Table of Contents •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; and •The absence of a prior year one-time tax settlement. The decreases were partially offset by: •Lower unrealized losses and higher realized gains on NDT funds; •Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd; •The favorable impacts of the multi-year plan at BGE and regulatory rate increases at DPL; and •Favorable weather conditions at PECO, 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. 122 -------------------------------------------------------------------------------- Table of Contents The following table provides a reconciliation between net income (loss) attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings (loss) for the three months endedMarch 31, 2021 compared to the same period in 2020.
Three Months Ended
2021 2020
Earnings per Earnings per
(In millions, except per share data) Diluted Share Diluted Share
Net Income (Loss) Attributable to Common
Shareholders $ (289) $ (0.30) $ 582 $ 0.60
Mark-to-Market Impact of Economic Hedging
Activities (net of taxes of $46 and $32 ,
respectively) (135) (0.14) (94) (0.10)
Unrealized Losses Related to NDT Fund
Investments (net of taxes of $40 and $405 ,
respectively)(a) 43 0.04 485 0.50
Asset Impairments (net of taxes of $1 ) - - 2 -
Plant Retirements and Divestitures (net of
taxes of $103 and $4 , respectively)(b) 310 0.32 13 0.01
Cost Management Program (net of taxes of $0
and $3 , respectively)(c) 1 - 9 0.01
Change in Environmental Liabilities (net of
taxes of $1 ) 2 - - -
COVID-19 Direct Costs (net of taxes of $4 )(d) 10 0.01 - -
Acquisition Related Costs (net of tax of
$2 )(e) 6 0.01 - -
ERP System Implementation Costs (net of taxes
of $1 )(f) 5 0.01 - -
Planned Separation Costs (net of taxes of
$2 )(g) 7 0.01 - -
Income Tax-Related Adjustments (entire amount
represents tax expense) (2) - (2) -
Noncontrolling Interests (net of taxes of $6
and $30 , respectively)(h) (17) (0.02) (144) (0.15)
Adjusted (non-GAAP) Operating Earnings (Loss) $ (60) $ (0.06) $ 851 $ 0.87
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between
GAAP Net Income (Loss) and Adjusted (non-GAAP) Operating Earnings (Loss) 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 losses related to NDT fund investments, the marginal statutory income
tax rates for 2021 and 2020 ranged from 25.0% to 29.0%. Under IRS regulations,
NDT fund investment returns are taxed at different rates for investments if they
are in qualified or non-qualified funds. The effective tax rates for the
unrealized losses related to NDT fund investments were 48.0% and 45.5% for the
three months ended March 31, 2021 and 2020, respectively.
(a)Reflects the impact of net unrealized 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 2021, primarily reflects accelerated depreciation and amortization
associated with Generation's decision in the third quarter of 2020 to early
retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in
2024, partially offset by a gain on sale of Generation's solar business. In
2020, primarily reflects accelerated depreciation and amortization expenses
associated with the early retirement of certain fossil sites.
(c)Primarily represents reorganization costs related to cost management
programs.
(d)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.
(e)Reflects costs related to the acquisition of EDF's interest in CENG.
(f)Reflects costs related to a multi-year Enterprise Resource Program (ERP)
system implementation.
(g)Represents costs related to the planned separation primarily comprised of
third-party costs paid to advisors, consultants, lawyers, and other experts
assisting in the planned separation as well as employee-related severance costs.
(h)Represents elimination from Generation's results of the noncontrolling
interests related to certain exclusion items, primarily related to unrealized
gains and losses on NDT fund investments for CENG units.
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Significant 2021 Transactions and Developments
Planned Separation
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.
On February 25, 2021 , Exelon and Generation filed applications with the FERC ,
NYPSC, and NRC seeking approvals for the separation of Generation. On March 25,
2021 , Exelon filed a request for a private letter ruling with the IRS to confirm
the tax-free treatment of the planned separation. Exelon and Generation expect a
decision from the FERC and the IRS in the third quarter of 2021, the NRC in the
fourth quarter of 2021, and have requested a decision from the NYPSC before the
end of 2021 but cannot predict if the applications will be approved as filed.
In connection with the planned separation, Exelon incurred transaction costs of
approximately $9 million on a pre-tax basis in the first quarter of 2021, which
are excluded from Adjusted (non-GAAP) Operating Earnings. The transaction costs
are primarily comprised of third-party costs paid to advisors, consultants,
lawyers, and other experts assisting in the planned separation as well as
employee-related severance costs.
There can be no assurance that any separation transaction will ultimately occur
or, if one does occur, of its terms or timing. See Note 19 - Planned Separation
of the Combined Notes to Consolidated Financial Statements for additional
information.
Impacts of the February 2021 Extreme Cold Weather Event and Texas -based
Generating Assets Outages
Beginning on February 15, 2021 , Generation's Texas -based generating assets
within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and
Handley, experienced outages as a result of extreme cold weather conditions. In
addition, those weather conditions drove increased demand for service,
dramatically increased wholesale power prices, and also increased gas prices in
certain regions.
The estimated impact to Exelon's and Generation's Net income for the first
quarter of 2021 arising from these market and weather conditions was a reduction
of approximately $880 million . The first quarter estimated impact includes
certain charges associated with the natural gas business that may be reduced
through waivers and/or recoveries from customers. Therefore, such charges are
not included in the estimated full year earnings impact. Exelon and Generation
estimate a reduction in Net income of approximately $670 million to $820 million
for the full year 2021. 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 or federal solutions to address the financial challenges
caused by the event, and related litigation and contract disputes. See Note 3 -
Regulatory Matters and Note 14 - Commitments and Contingencies of the Combined
Notes to Consolidated Financial Statements for additional information.
Exelon expects to offset between $410 million and $490 million of this impact
for the full year 2021 primarily at Generation through a combination of enhanced
revenue opportunities, deferral of selected non-essential maintenance, and
primarily one-time cost savings.
Agreement for the Sale of a Generation Biomass Facility (Exelon and Generation)
On April 28, 2021 , Generation and ReGenerate entered into a purchase agreement,
under which ReGenerate agreed to purchase Generation's interest in the Albany
Green Energy biomass facility. Completion of the transaction is expected in the
second half of 2021.
As a result, in the second quarter of 2021, Exelon and Generation will
reclassify these assets and liabilities as held for sale and expect to record an
impairment loss in a range of $135 million to $150 million on a pre-tax basis,
which will be excluded from Exelon's and Generation's Adjusted (non-GAAP)
Operating Earnings. See Note 2 - Mergers, Acquisitions, and Dispositions of the
Combined Notes to Consolidated Financial Statements for additional information.
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Utility Rates and Base Rate 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 2021. 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 16, 2020 Electric $ (11) $ (14) 8.38 % December 9, 2020 January 1, 2021
BGE - Maryland May 15, 2020 (amended Electric 137 81 9.50 % December 16, 2020 January 1, 2021
September 11, 2020) Natural Gas 91 21 9.65 %
Pending Distribution Base Rate Case Proceedings
Requested
Revenue
Requirement
Registrant/Jurisdiction Filing Date Service Increase Requested ROE Expected Approval Timing
ComEd - Illinois April 16, 2021 Electric $ 51 7.36 % Fourth quarter of 2021
PECO - Pennsylvania March 30, 2021 Electric 246 10.95 % Fourth quarter of 2021
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 (amended Electric 104 10.2 % Second quarter of 2021
March 31, 2021)
DPL - Delaware March 6, 2020 (amended Electric 23 10.3 % Third quarter of 2021
February 2, 2021)
ACE - New Jersey December 9, 2020 (amended Electric 67 10.3 % Fourth quarter of 2021
February 26, 2021)
Transmission Formula Rates The following total increases were included in ComEd's 2021 electric transmission formula rate update. 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 on
Registrant Increase Increase Increase Rate Base Allowed ROE
ComEd $ 33 $ 12 $ 45 8.20 % 11.50 %
125
-------------------------------------------------------------------------------- Table of Contents Other Key Business Drivers and Management Strategies The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Key Business Drivers and Management Strategies in the Registrants' combined 2020 Form 10-K and Note 14 - Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters. Power Markets 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. Several consumer advocates filed a complaint seeking similar relief several months after the IMM's complaint. OnMarch 18, 2021 ,FERC granted the complaints, finding the current estimate of performance assessment intervals to be excessive compared to the reasonably expected number of performance assessment intervals which results in an unjust and unreasonable default offer cap.FERC did not establish the number of performance assessment intervals that should be used to calculate the default offer cap and instead request briefs on the matter, including alternative approaches to mitigation in the capacity market.FERC clarified that the capacity auction for delivery year 2022/2023 (scheduled forMay 2021 ) should go forward as scheduled under the current rules. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation. 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 ofMarch 31, 2021 , 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. 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 11 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 3. 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. 126
-------------------------------------------------------------------------------- Table of Contents Other Legislative and Regulatory Developments FERC Supplemental Notice of Proposed Rulemaking OnApril 15, 2021 , theFERC issued a Supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify the current regulation permitting a continuous 50-basis-point ROE incentive adder for a transmission utility that joins and remains a member of a RTO. Under the NOPR, the ROE incentive adder would only be available for a period of up to three years after a transmission utility newly joins a RTO and all existing ROE incentive adders would end for transmission utilities that have been members for three or more years. The Utility Registrants' existing transmission rates include the ROE incentive adder. Exelon plans to provide comments toFERC on this matter which are due byMay 26, 2021 . Exelon cannot predict the outcome, but a final rule as proposed could have an adverse impact to Exelon's and the Utility Registrants' financial statements. See Note 3 - Regulatory Matters of the 2020 Form 10-K for additional information regarding the Utility Registrants' transmission formula rates and regulatory proceedings at theFERC . Employees InApril 2021 , PECO ratified two CBAs withIBEW Local 614 which covers 1,140 operations employees and 185 customer service employees, respectively. Both CBAs expire in 2026. Critical Accounting Policies and Estimates Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. AtMarch 31, 2021 , the Registrants' critical accounting policies and estimates had not changed significantly fromDecember 31, 2020 . See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Critical Accounting Policies and Estimates in the Registrants' 2020 Form 10-K for further information. 127
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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.
Three Months Ended Favorable
March 31, (Unfavorable)
2021 2020 Variance
Operating revenues $ 5,559 $ 4,733 $ 826
Purchased power and fuel expense 4,610 2,704 (1,906)
Revenues net of purchased power and fuel expense 949 2,029 (1,080)
Other operating expenses
Operating and maintenance 1,001 1,263 262
Depreciation and amortization 940 304 (636)
Taxes other than income taxes 121 129 8
Total other operating expenses 2,062 1,696 (366)
Gain on sales of assets and businesses 71 - 71
Operating (loss) income (1,042) 333 (1,375)
Other income and (deductions)
Interest expense, net (72) (109) 37
Other, net 167 (771) 938
Total other income and (deductions) 95 (880) 975
Loss before income taxes (947) (547) (400)
Income taxes (179) (389) (210)
Equity in losses of unconsolidated affiliates (1) (3) 2
Net loss (769) (161) (608)
Net income (loss) attributable to noncontrolling
interests 24 (206) 230
Net (loss) income attributable to membership interest $ (793) $ 45 $ (838)
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020 .
Net income attributable to membership interest decreased by $838 million
primarily due to:
•Impacts of the February 2021 extreme cold weather event;
•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; and
•The absence of a prior year one-time tax settlement.
The decreases were partially offset by:
•Lower unrealized losses and higher realized gains on NDT funds.
Revenues Net of Purchased 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-
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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 and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements. For the three months endedMarch 31, 2021 compared to 2020, 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. Three Months Ended March 31, 2021 2020 Variance % Change Mid-Atlantic(a)$ 567 $ 567 $ - - % Midwest(b) 702 727 (25) (3.4) % New York 242 193 49 25.4 % ERCOT (1,184) 80 (1,264) (1,580.0) % Other Power Regions 217 158 59 37.3 % Total electric revenues net of purchased power and fuel expense 544 1,725 (1,181) (68.5) % Mark-to-market gains 175 131 44 33.6 % Other 230 173 57 32.9 % Total revenue net of purchased power and fuel expense$ 949 $ 2,029 $ (1,080) (53.2) % __________
(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:
Three Months Ended
March 31,
Supply Source (GWhs) 2021 2020 Variance % Change
Nuclear Generation(a)
Mid-Atlantic 13,254 12,784 470 3.7 %
Midwest 23,155 23,598 (443) (1.9) %
New York 7,057 6,173 884 14.3 %
Total Nuclear Generation 43,466 42,555 911 2.1 %
Fossil and Renewables
Mid-Atlantic 662 853 (191) (22.4) %
Midwest 323 388 (65) (16.8) %
New York 1 1 - - %
ERCOT 2,783 3,012 (229) (7.6) %
Other Power Regions 2,964 3,508 (544) (15.5) %
Total Fossil and Renewables 6,733 7,762 (1,029) (13.3) %
Purchased Power
Mid-Atlantic 4,483 5,943 (1,460) (24.6) %
Midwest 179 288 (109) (37.8) %
ERCOT 772 991 (219) (22.1) %
Other Power Regions 12,834 12,167 667 5.5 %
Total Purchased Power 18,268 19,389 (1,121) (5.8) %
Total Supply/Sales by Region
Mid-Atlantic(b) 18,399 19,580 (1,181) (6.0) %
Midwest(b) 23,657 24,274 (617) (2.5) %
New York 7,058 6,174 884 14.3 %
ERCOT 3,555 4,003 (448) (11.2) %
Other Power Regions 15,798 15,675 123 0.8 %
Total Supply/Sales by Region 68,467 69,706 (1,239) (1.8) %
__________
(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.
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Generation
For the three months endedMarch 31, 2021 compared to 2020, changes in RNF by region were as follows: (Decrease)/ 2021 vs. 2020 Increase Description Mid-Atlantic $ -
• increased capacity revenue, offset
by
• decreased load served
Midwest (25) • decreased load served
• decreased total ISO sales due to
decreased generation
New York 49 • decreased nuclear outage days
• increased ZEC revenues due to
decreased nuclear outage days
ERCOT (1,264) • higher energy procurement costs due
to the
weather event, as well as the impact
of ERCOT market participant defaults
Other Power Regions 59 • increase in newly contracted load
• higher portfolio optimization
• higher realized energy prices,
partially offset by
• decreased capacity revenue
Mark-to-market(a) 44 • gains on economic hedging activities
of
gains of $175 million in 2021
Other 57 • higher natural gas portfolio
optimization partially offset by
penalties associated with operational
flow orders and curtailments as a
result of the
cold weather event, partially offset
by
• increase in accelerated nuclear fuel
amortization associated with announced
early plant retirements
• decreased revenue related to the
energy efficiency business
Total $ (1,080)
__________
(a)See Note 11 - Derivative Financial Instruments of the Combined Notes to
Consolidated Financial Statements for additional information on mark-to-market
gains.
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, excluding Salem , 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
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Generation
GAAP and may not be comparable to other companies' presentations or be more useful than the GAAP information provided elsewhere in this report.
Three Months Ended
March 31,
2021 2020
Nuclear fleet capacity factor 95.3 % 93.9 %
Refueling outage days 84 94
Non-refueling outage days 3 11
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2021
Increase (Decrease)
Credit loss expense $ 47
Labor, other benefits, contracting, and materials(a) (27)
Nuclear refueling outage costs, including the co-owned
(51)
Plant retirements and divestitures (221)
Other (10)
Total decrease $ (262)
__________
(a)Primarily reflects decreased contracting costs.
Depreciation and amortization expense for the three months ended March 31, 2021
compared to the same period in 2020 increased primarily due to the accelerated
depreciation and amortization associated with Generation's decision to early
retire the Byron and Dresden nuclear facilities.
Gain on sales of assets and businesses for the three months ended March 31, 2021
compared to the same period in 2020 increased primarily due to a gain on sale of
Generation's solar business.
Interest Expense for the three months ended March 31, 2021 compared to the same
period in 2020 decreased primarily due to decreases in interest rates.
Other, net for the three months ended March 31, 2021 compared to the same period
in 2020 increased due to activity described in the table below:
Three Months Ended
March 31,
2021 2020
Net unrealized losses on NDT funds(a) $ (66) $ (706)
Net realized gains on sale of NDT funds(a) 185 55
Interest and dividend income on NDT funds(a) 18 27
Contractual elimination of income tax expense(b) 42 (176)
Net unrealized losses from equity investments(c) (23) -
Other 11 29
Total other, net $ 167 $ (771)
__________
(a)Unrealized losses, 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)Net unrealized losses on equity investments that became publicly traded
entities in the fourth quarter of 2020 and the first quarter of 2021.
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Effective income tax rates were 18.9% and 71.1% for the three months endedMarch 31, 2021 and 2020, respectively. See Note 9 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information Net income attributable to noncontrolling interests for the three months endedMarch 31, 2021 compared to the same period in 2020 increased primarily due to higher net gains on NDT fund investments for CENG. 133 --------------------------------------------------------------------------------
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ComEd
Results of Operations - ComEd
Three Months Ended Favorable
March 31, (Unfavorable)
2021 2020 Variance
Operating revenues $ 1,535 $ 1,439 $ 96
Operating expenses
Purchased power expense 527 486 (41)
Operating and maintenance 316 317 1
Depreciation and amortization 292 273 (19)
Taxes other than income taxes 75 75 -
Total operating expenses 1,210 1,151 (59)
Operating income 325 288 37
Other income and (deductions)
Interest expense, net (96) (94) (2)
Other, net 7 10 (3)
Total other income and (deductions) (89) (84) (5)
Income before income taxes 236 204 32
Income taxes 39 36 (3)
Net income $ 197 $ 168 $ 29 Three Months Ended
Three Months Ended
March 31, 2021
Increase
Distribution $ 21
Transmission 2
Energy efficiency 12
Other 12
47
Regulatory required programs 49
Total increase $ 96
Revenue Decoupling. The demand for electricity is affected by weather conditions
and customer usage. Operating revenues are not impacted by abnormal weather,
usage per customer or number of customers as a result of the revenue decoupling
mechanisms as allowed by FEJA.
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. Electric
distribution revenue increased for the three months ended March 31, 2021 as
compared to the same period in 2020, due to the impact of higher rate base and
higher allowed ROE due to an increase in treasury rates.
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.
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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 during the three months endedMarch 31, 2021 as compared to the same period in 2020, primarily due to increased regulatory asset amortization, which is fully recoverable. Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. The increase in Other revenue for the three months endedMarch 31, 2021 as compared to the same period in 2020, 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$41 million for the three months endedMarch 31, 2021 compared to the same period in 2020, respectively, in Purchased power expense is offset in Operating revenues as part of regulatory required programs. The changes in Operating and maintenance expense consisted of the following: Three Months Ended March 31, 2021 (Decrease) Increase Storm-related costs $ (9) Labor, other benefits, contracting and materials 8 Pension and non-pension postretirement benefits expense 1 Other (6) (6) Regulatory required programs(a) 5 Total decrease $ (1)
__________
(a)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.
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The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2021
Increase
Depreciation and amortization(a) $ 11
Regulatory asset amortization(b) 8
Total increase $ 19
__________
(a)Reflects ongoing capital expenditures.
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory
asset and amortization related to the August 2020 storm regulatory asset.
Effective income tax rates were 16.5% and 17.6% for the three months ended March
31, 2021 and 2020, respectively. See Note 9 - 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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PECO
Results of Operations - PECO
Three Months Ended Favorable
March 31, (Unfavorable)
2021 2020 Variance
Operating revenues $ 889 $ 813 $ 76
Operating expenses
Purchased power and fuel expense 316 283 (33)
Operating and maintenance 234 217 (17)
Depreciation and amortization 86 86 -
Taxes other than income taxes 43 39 (4)
Total operating expenses 679 625 (54)
Operating income 210 188 22
Other income and (deductions)
Interest expense, net (38) (36) (2)
Other, net 5 3 2
Total other income and (deductions) (33) (33) -
Income before income taxes 177 155 22
Income taxes 10 15 5
Net income $ 167 $ 140 $ 27
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020 .
Net income increased by $27 million primarily due to favorable weather
conditions and volume.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2021
Increase (Decrease)
Electric Gas Total
Weather $ 21 $ 16 $ 37
Volume 12 2 14
Pricing (6) (1) (7)
Transmission 1 - 1
Other (2) - (2)
26 17 43
Regulatory required programs 31 2 33
Total increase $ 57 $ 19 $ 76
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. During the three
months ended March 31, 2021 compared to the same period in 2020, Operating
revenues related to weather increased by the impact of favorable 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
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PECO
PECO's service territory for the three months ended
% Change
2021 2020 Normal From 2020 2021 vs. Normal
Three Months EndedMarch 31 , Heating Degree-Days 2,302 1,989 2,418 15.7 % (4.8) % Cooling Degree-Days 5 - 1 n/a 400.0 %
Volume. Electric volume, exclusive of the effects of weather, for the three
months ended
Three Months Ended March 31, Weather -
Electric Retail Deliveries to Customers (in Normal
GWhs) 2021 2020 % Change % Change(b)
Residential 3,767 3,254 15.8 % 6.2 %
Small commercial & industrial 1,881 1,905 (1.3) % (5.1) %
Large commercial & industrial 3,272 3,421 (4.4) % (5.0) %
Public authorities & electric railroads 149 151 (1.3) % (1.4) %
Total electric retail deliveries(a) 9,069 8,731 3.9 % (0.6) %
As of March 31,
Number of Electric Customers 2021 2020
Residential 1,512,255 1,499,019
Small commercial & industrial 154,637 154,056
Large commercial & industrial 3,109 3,093
Public authorities & electric railroads 10,237 10,096
Total 1,680,238 1,666,264
__________
(a)Reflects delivery volumes 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.
Three Months Ended Weather -
Natural Gas Deliveries to Customers (in March 31, Normal
mmcf) 2021 2020 % Change % Change(b)
Residential 20,674 17,282 19.6 % 2.8 %
Small commercial & industrial 10,170 8,809 15.5 % (0.2) %
Large commercial & industrial 7 9 (22.2) % (0.6) %
Transportation 7,650 7,135 7.2 % 0.4 %
Total natural gas retail deliveries(a) 38,501 33,235 15.8 % 1.5 %
As of March 31,
Number of Natural Gas Customers 2021 2020
Residential 493,857 489,063
Small commercial & industrial 44,604 44,509
Large commercial & industrial 5 5
Transportation 685 727
Total 539,151 534,304
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from
PECO and customers purchasing natural gas from a competitive natural gas
supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on
the historical 30-year average.
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PECO
Pricing for the three months endedMarch 31, 2021 compared to the same period in 2020 decreased primarily due to lower overall effective electric rates due to increased usage across all major customer classes. Transmission Revenue. Under aFERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. 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. Other revenue primarily includes revenue related to late payment charges. Other revenues for the three months endedMarch 31, 2021 compared to the same period in 2020, 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. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation. The increase of$33 million for the three months endedMarch 31, 2021 compared to the same period in 2020, 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: Three Months Ended March 31, 2021 Increase (Decrease) Labor, other benefits, contracting and materials 10 Credit loss expense 7 Storm-related costs 6 BSC costs 3 Regulatory Required Programs (2) Other (7) Total increase $ 17
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2021
Increase (Decrease)
Depreciation and amortization(a) $ 3
Regulatory asset amortization (3)
Total increase $ -
__________
(a)Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Interest expense, net increased $2 million for the three months ended March 31,
2021 compared to the same period in 2020, respectively, primarily due to the
issuance of debt in June 2020 and March 2021 .
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PECO
Effective income tax rates were 5.6% and 9.7% for the three months endedMarch 31, 2021 and 2020, respectively. See Note 9 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 140 --------------------------------------------------------------------------------
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BGE
Results of Operations - BGE
Three Months Ended Favorable
March 31, (Unfavorable)
2021 2020 Variance
Operating revenues $ 974 $ 937 $ 37
Operating expenses
Purchased power and fuel expense 331 288 (43)
Operating and maintenance 197 188 (9)
Depreciation and amortization 152 143 (9)
Taxes other than income taxes 72 69 (3)
Total operating expenses 752 688 (64)
Operating income 222 249 (27)
Other income and (deductions)
Interest expense, net (34) (32) (2)
Other, net 8 5 3
Total other income and (deductions) (26) (27) 1
Income before income taxes 196 222 (26)
Income taxes (13) 41 54
Net income $ 209 $ 181 $ 28
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020 .
Net income increased by $28 million primarily due to favorable impacts of the
multi-year plan. See Note 3 - Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information on the three-year
electric and natural gas distribution multi-year plan.
The changes in Operating revenues consisted of the following:
Three Months Ended
March 31, 2021
(Decrease) Increase
Electric Gas Total
Distribution $ - $ (1) $ (1)
Transmission 3 - 3
Other (7) (1) (8)
(4) (2) (6)
Regulatory required programs 24 19 43
Total increase $ 20 $ 17 $ 37
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 March 31,
Number of Electric Customers 2021 2020
Residential 1,192,470 1,181,329
Small commercial & industrial 114,819 114,697
Large commercial & industrial 12,505 12,376
Public authorities & electric railroads 266
265
Total 1,320,060 1,308,667
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BGE
As of March 31,
Number of Natural Gas Customers 2021 2020
Residential 648,824 641,608
Small commercial & industrial 38,318 38,381
Large commercial & industrial 6,120 6,078
Total 693,262 686,067
Distribution Revenue remained relatively consistent for the three months ended
March 31, 2021 , compared to the same period in 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 year. Generally,
increases/decreases in the highest daily peak load will result in higher/lower
transmission revenue.
Other Revenue includes revenue related to late payment charges, mutual
assistance, off-system sales, and service application fees.
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.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial
Statements for the presentation of BGE's revenue disaggregation.
The increase of $43 million for the three months ended March 31, 2021 compared
to the same period in 2020, in Purchased power and fuel expense is fully offset
in Operating revenues as part of regulatory required programs.
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BGE
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2021
Increase (Decrease)
Storm-related costs $ 6
BSC costs 2
Credit loss expense (2)
Other 3
Total increase $ 9
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2021
Increase
Depreciation and amortization(a) $ 9
Total increase $ 9
_________
(a)Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Effective income tax rates were (6.6)% and 18.5% for the three months ended
March 31, 2021 and 2020, respectively. The change is primarily due to the
multi-year plan which resulted in the acceleration of certain income tax
benefits. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated
Financial Statements for additional information on the three-year electric and
natural gas distribution multi-year plan and Note 9 - 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 three months endedMarch 31, 2021 compared to the same period in 2020. See the Results of Operations for Pepco, DPL, and ACE for additional information. Three Months Ended March 31, 2021 2020 Favorable Variance PHI$ 128 $ 108$ 20 Pepco 59 52 7 DPL 56 45 11 ACE 14 13 1 Other(a) (1) (2) 1 _________ (a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities. Three Months EndedMarch 31, 2021 Compared to Three Months EndedMarch 31, 2020 . Net Income increased by$20 million primarily due to favorable weather conditions in DPL'sDelaware and ACE's service territories and higher electric distribution rates at DPL. 144
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Pepco
Results of Operations - Pepco
Three Months Ended Favorable
March 31, (Unfavorable)
2021 2020 Variance
Operating revenues $ 553 $ 544 $ 9
Operating expenses
Purchased power expense 166 164 (2)
Operating and maintenance 108 111 3
Depreciation and amortization 102 95 (7)
Taxes other than income taxes 90 92 2
Total operating expenses 466 462 (4)
Operating income 87 82 5
Other income and (deductions)
Interest expense, net (34) (34) -
Other, net 12 9 3
Total other income and (deductions) (22) (25) 3
Income before income taxes 65 57 8
Income taxes 6 5 (1)
Net income $ 59 $ 52 $ 7
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020 .
Net income remained relatively consistent.
The changes in Operating revenues consisted of the following:
Three Months Ended March 31, 2021
Increase (Decrease)
Distribution $ 3
Transmission (3)
Other 4
4
Regulatory required programs 5
Total increase $ 9
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 March 31,
Number of Electric Customers 2021 2020
Residential 835,415 820,283
Small commercial & industrial 53,738 54,304
Large commercial & industrial 22,492 22,248
Public authorities & electric railroads 174 169
Total 911,819 897,004
Distribution Revenue increased for the three months ended
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Pepco
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, 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 increase of$2 million for the three months endedMarch 31, 2021 compared to the same period in 2020, 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: Three Months Ended March 31, 2021 (Decrease) Increase Labor, other benefits, contracting and materials $ (6) Pension and non-pension postretirement benefits expense (1) BSC and PHISCO costs 1 Credit loss expense 2 Other 1 Total decrease $ (3) The changes in Depreciation and amortization expense consisted of the following: Three Months Ended March 31, 2021 Increase (Decrease)
Depreciation and amortization(a) $ 4
Regulatory asset amortization (1)
Regulatory required programs 4
Total increase $ 7
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Effective income tax rates were 9.2% and 8.8% for the three months endedMarch 31, 2021 and 2020, respectively. See Note 9 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. 146 -------------------------------------------------------------------------------- Table of Contents DPL Results of Operations - DPL Three Months Ended Favorable March 31, (Unfavorable) 2021 2020 Variance Operating revenues$ 382 $ 350$ 32 Operating expenses Purchased power and fuel expense 156 141 (15) Operating and maintenance 83 79 (4) Depreciation and amortization 53 48 (5) Taxes other than income taxes 17 16 (1) Total operating expenses 309 284 (25) Operating income 73 66 7 Other income and (deductions) Interest expense, net (15) (16) 1 Other, net 3 2 1 Total other income and (deductions) (12) (14) 2 Income before income taxes 61 52 9 Income taxes 5 7 2 Net income$ 56 $ 45$ 11 Three Months EndedMarch 31, 2021 Compared to Three Months EndedMarch 31, 2020 . Net income increased by$11 million primarily due to favorable weather conditions in DPL'sDelaware electric and natural gas service territories and higher electric distribution rates. The changes in Operating revenues consisted of the following: Three Months Ended March 31, 2021 Increase (Decrease) Electric Gas Total Weather$ 4 $ 5 $ 9 Volume - 1 1 Distribution 5 - 5 Other 1 (1) - 10 5 15 Regulatory required programs 15 2 17 Total increase$ 25 $ 7 $ 32 Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution inMaryland 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 customers inMaryland 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 inDelaware 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 three months endedMarch 31, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to the impact of favorable weather conditions in DPL'sDelaware electric and natural gas service territories. 147 --------------------------------------------------------------------------------
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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 three months endedMarch 31, 2021 compared to same period in 2020 and normal weather consisted of the following: Delaware Electric Service Territory % Change Three Months Ended March 31, 2021 2020 Normal 2021 vs. 2020 2021 vs. Normal Heating Degree-Days 2,358 2,003 2,493 17.7 % (5.4) % Cooling Degree-Days 3 - - n/a n/a Delaware Natural Gas Service Territory % Change Three Months Ended March 31, 2021 2020 Normal 2021 vs. 2020 2021 vs. Normal Heating Degree-Days 2,358 2,003 2,497 17.7 % (5.6) %
Volume, exclusive of the effects of weather, remained relatively consistent for
the three months ended
Three Months Ended
Electric Retail Deliveries to Delaware Customers March 31, Weather - Normal
(in GWhs) 2021 2020 % Change % Change(b)
Residential 854 743 14.9 % 4.5 %
Small commercial & industrial 342 296 15.5 % 10.5 %
Large commercial & industrial 689 823 (16.3) % (17.2) %
Public authorities & electric railroads 9 8 12.5 % 7.7 %
Total electric retail deliveries(a) 1,894 1,870 1.3 % (3.6) %
As of March 31,
Number of Total Electric Customers (Maryland and
Delaware) 2021 2020
Residential 473,917 469,082
Small commercial & industrial 62,647 61,769
Large commercial & industrial 1,208 1,414
Public authorities & electric railroads 608 612
Total 538,380 532,877
_________
(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.
Three Months Ended
Natural Gas Retail Deliveries to Delaware March 31, Weather - Normal
Customers (in mmcf) 2021 2020 % Change % Change(b)
Residential 4,394 3,647 20.5 % 2.6 %
Small commercial & industrial 1,868 1,671 11.8 % (3.9) %
Large commercial & industrial 457 452 1.1 % 1.1 %
Transportation 2,224 2,108 5.5 % (0.9) %
Total natural gas deliveries(a) 8,943 7,878 13.5 % 0.2 %
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DPL
As of March 31,
Number of Delaware Natural Gas Customers 2021 2020
Residential 127,522 126,209
Small commercial & industrial 10,043 10,004
Large commercial & industrial 19 17
Transportation 160 159
Total 137,744 136,389
__________
(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 three months endedMarch 31, 2021 compared to the same period in 2020 primarily due to higher electric distribution rates inMaryland that became effective inJuly 2020 and higher electric and natural gas distribution rates inDelaware that became effective in the second half of 2020. Transmission Revenues. 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. 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 increase of$15 million for the three months endedMarch 31, 2021 , compared to the same period in 2020, 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: Three Months Ended March 31, 2021 Increase (Decrease) Labor, other benefits, contracting and materials $ 2 BSC and PHISCO costs 2 Credit loss expense 1 Pension and non-pension postretirement benefits expense (1) Total increase $ 4 149
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DPL
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2021
Increase
Depreciation and amortization(a) $ 3
Regulatory required programs 2
Total increase $ 5
_________
(a)Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Effective income tax rates were 8.2% and 13.5% for the three months ended March
31, 2021 and 2020, respectively. See Note 9 - 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
Three Months Ended Favorable
March 31, (Unfavorable)
2021 2020 Variance
Operating revenues $ 310 $ 276 $ 34
Operating expenses
Purchased power expense 157 128 (29)
Operating and maintenance 76 78 2
Depreciation and amortization 47 43 (4)
Taxes other than income taxes 2 2 -
Total operating expenses 282 251 (31)
Gain on sale of assets - 2 (2)
Operating income 28 27 1
Other income and (deductions)
Interest expense, net (15) (15) -
Other, net 1 2 (1)
Total other income and (deductions) (14) (13) (1)
Income before income taxes 14 14 -
Income taxes - 1 1
Net income $ 14 $ 13 $ 1
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020 .
Net income remained relatively consistent.
The changes in Operating revenues consisted of the following:
Three Months Ended March 31, 2021
Increase (Decrease)
Weather $ 4
Volume 2
Distribution (1)
Other 1
6
Regulatory required programs 28
Total increase $ 34
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 an increase related to
weather for the three months ended March 31, 2021 compared to same period in
2020 due to the impact of favorable weather conditions in ACE'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
20-year period in ACE's service territory. The changes in heating and cooling
degree days in ACE's service territory for the three months ended March 31, 2021
compared to same period in 2020 and normal weather consisted of the following:
Heating and Cooling
Degree-Days % Change
Three Months Ended March 31, 2021 2020 Normal 2021 vs. 2020 2021 vs. Normal
Heating Degree-Days 2,348 1,948 2,469 20.5 % (4.9) %
Cooling Degree-Days 4 - - n/a n/a
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ACE
Volume, exclusive of the effects of weather, increased for the three months endedMarch 31, 2021 compared to the same period in 2020, primarily due to residential customer growth and usage, partially offset by lower commercial and industrial usage. Three Months Ended March 31, Weather - Normal Electric Retail Deliveries to Customers (in GWhs) 2021 2020 % Change % Change(b) Residential 928 810 14.6 % 6.6 % Small commercial & industrial 305 294 3.7 % (0.8) % Large commercial & industrial 716 735 (2.6) % (3.5) % Public authorities & electric railroads 13 13 - % 0.9 % Total electric retail deliveries(a) 1,962 1,852 5.9 % 1.5 % As of March 31, Number of Electric Customers 2021 2020 Residential 498,396 495,444 Small commercial & industrial 61,771 61,470 Large commercial & industrial 3,267 3,355 Public authorities & electric railroads 704 684 Total 564,138 560,953
_________
(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 remained relatively consistent for the three months endedMarch 31, 2021 compared to the same period in 2020. Transmission Revenues. 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. 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. 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$29 million for the three months endedMarch 31, 2021 compared to the same period in 2020, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs. 152 --------------------------------------------------------------------------------
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The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2021
Increase (Decrease)
Labor, other benefits, contracting and materials $ 1
BSC and PHISCO costs 1
2
Regulatory required programs(a) (4)
Total decrease $ (2)
_________
(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:
Three Months Ended March 31, 2021
Increase (Decrease)
Depreciation and amortization(a) $ 4
Regulatory asset amortization (1)
Regulatory required programs 1
Total increase $ 4
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures. Gain on sale of assets for the three months endedMarch 31, 2021 compared to the same period in 2020 decreased due to the sale of land in the first quarter of 2020. Effective income tax rates were 0.0% and 7.1% for the three months endedMarch 31, 2021 and 2020, respectively. See Note 9 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. 153 -------------------------------------------------------------------------------- Table of Contents 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, 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 . The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the "Credit Matters" section below for 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 12 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants' debt and credit agreements. 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 8 - Nuclear Decommissioning 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 providing additional financial assurances such as letters of credit or parent company guarantees 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. No later than 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 early 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, additional financial assurance may be required. 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$55 million . 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 154
-------------------------------------------------------------------------------- Table of Contents 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. Based on current projections of the most likely decommissioning approach and expected exemptions from the NRC, 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$180 million , net of taxes, over a period of 10 years after permanent shutdown. As ofMarch 31, 2021 , Generation is not required to provide any additional financial assurances 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. Refer to Note 17 - Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on credit facilities and nonrecourse debt. 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 and the sale of certain receivables. 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 of the Exelon 2020 Form 10-K for additional information on regulatory and legal proceedings and proposed legislation. 155
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The following table provides a summary of the change in cash flows from
operating activities for the three months ended
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