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 4 - 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. 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. We have implemented work from home policies where appropriate, and imposed travel limitations on our 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 have been no changes in internal control over financial reporting to date in 2020 as of 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 4. Controls and Procedures for additional information. The estimated impact to Generation's and the Utility Registrants' Net income as a result of COVID-19 is approximately$100 million and$50 million , respectively, for the three and six months endedJune 30, 2020 and primarily reflects the impact of reduction in load, incremental credit loss expense and direct costs related to COVID-19 as further discussed below. Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas in the second quarter of 2020 and are expected to continue to impact demand in the second half of 2020. Commercial and Industrial customer demand has experienced a notable decrease, while residential demand has slightly increased. Generation and the Utility Registrants estimate a net decrease in Net income due to reduction in load of$50 to$100 million and$10 to$25 million , respectively, in the second half of 2020. Generation and the Utility Registrants load forecasts are highly dependent on many factors including, but not limited to, the duration of remaining restrictions and the speed and strength of the economic recovery. A 1% change in load would result in the following change in Net income in the second half of 2020: 141
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Utility Registrants' Net
Generation's Net Income Income
Commercial & Industrial Customers $ 8 $ 4
Residential Customers 4 4
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. These measures were in place through July 1, 2020 for DPL
Delaware and July 15, 2020 for ACE and are currently expected to continue
through August 31, 2020 for ComEd, September 1, 2020 for BGE, Pepco Maryland and
DPL Maryland, October 9, 2020 for Pepco District of Columbia and until further
notice for PECO. As a result of such measures, the Registrants expect an
increase in Customer allowance for credit losses for the year ending December
31, 2020 . Generation estimates a decrease in Net income due to an increase in
credit loss expense of $15 to $50 million in the second half of 2020. The
Utility Registrants do not expect a material decrease in Net income for the year
ending December 31, 2020 . Typically, they recover credit loss expense through
rate required programs or distribution base rate cases. For those jurisdictions
without an existing rate required program to recover credit loss expense, the
Utility Registrants are pursuing strategies with their respective commissions to
recover incremental costs being incurred as a result of COVID-19. During April,
May, and July of 2020, the MDPSC, the DCPSC, the DPSC, and the NJBPU issued
orders authorizing the creation of regulatory assets to track incremental
COVID-19 related costs. Also, in May of 2020, the PAPUC issued a Secretarial
Letter authorizing the creation of regulatory assets to track incremental credit
loss expense related to COVID-19. Such orders and the Secretarial Letter will
allow for assessment of recovery of those costs in future distribution base rate
cases. ComEd and ACE have existing mechanisms for recovery of credit loss
expense. The other Utility Registrants are assessing the regulatory facts and
circumstances and expect to record regulatory assets in the second half of 2020
for the incremental credit loss expense related to COVID-19, including the
expense recorded in the second quarter of 2020. However, the timing and amount
of the recovery offset of the increase in credit loss expense could extend
beyond 2020, which could have a negative impact on Net income for the year
ending December 31, 2020 .
The 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. Such costs are excluded from Adjusted (non-GAAP)
Operating Earnings.
To offset part of the unfavorable impacts from reduction in load, increase in
credit loss expense and direct costs related to COVID-19, the Registrants
identified and are pursuing approximately $250 million in cost savings across
Generation and the Utility Registrants.
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 on April 3,
2020 . Generation also entered into two short-term loan agreements in March of
2020 for an aggregate of $500 million . On April 8, 2020 , Generation received
approximately $500 million in cash after entering into an accounts receivable
financing arrangement. On April 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, to date in
2020, the Registrants have issued long-term debt of $5.1 billion , of which $4.0
billion was issued in the period of April to July of 2020. The Registrants
accelerated the timing of a number of planned debt issuances resulting in the
$4.0 billion issued in the period of April to July of 2020 and the Registrants
have now completed their planned long-term debt issuances for the 2020 year. See
Liquidity and Capital Resources, Note 12 - Debt and Credit Agreements, and Note
5 - 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 to date in
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 our workforce, our customers and our suppliers and we will take
additional precautions that we determine are necessary in order to mitigate the
impacts. The extent to which
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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. 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 three and six months endedJune 30, 2020 compared to the same period in 2019. For additional information regarding the financial results for the three and six months endedJune 30, 2020 and 2019 see the discussions of Results of Operations by Registrant. Three Months Ended June 30, Favorable (unfavorable) Six Months Ended June 30, Favorable (unfavorable) 2020 2019 variance 2020 2019 variance Exelon 521 484 $ 37$ 1,103 $ 1,391 $ (288 ) Generation 476 108 368 521 472 49 ComEd (61 ) 186 (247 ) 107 344 (237 ) PECO 39 102 (63 ) 178 270 (92 ) BGE 39 45 (6 ) 219 206 13 PHI 94 106 (12 ) 202 223 (21 ) Pepco 57 64 (7 ) 109 119 (10 ) DPL 19 30 (11 ) 64 83 (19 ) ACE 18 14 4 31 24 7 Other(a) (66 ) (63 ) (3 ) (124 ) (124 ) - __________
(a) Primarily includes eliminating and consolidating adjustments, Exelon's
corporate operations, shared service entities and other financing and
investing activities.
Three Months EndedJune 30, 2020 Compared to Three Months EndedJune 30, 2019 . Net income attributable to common shareholders increased by$37 million and diluted earnings per average common share increased to$0.53 in 2020 from$0.50 in 2019 primarily due to: • Higher net unrealized and realized gains on NDT funds;
• Higher mark-to-market gains;
• Lower operating and maintenance expense primarily due to lower contracting
costs at Generation; and
• Favorable weather conditions at PECO and DPL Delaware.
The increases were partially offset by: • Payments that ComEd will make under the Deferred Prosecution Agreement.
See Note 14 - 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;
• Higher storm costs related to the
• Higher credit loss expense that includes the impacts of COVID-19 at
Generation, PECO, Pepco and DPL;
• COVID-19 direct costs; and
• Lower electric distribution earnings at ComEd primarily due to
distribution formula rate timing.
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Six Months EndedJune 30, 2020 Compared to Six Months EndedJune 30, 2019 . Net income attributable to common shareholders decreased by$288 million and diluted earnings per average common share decreased to$1.13 in 2020 from$1.43 in 2019 primarily due to: • Payments that ComEd will make under the Deferred Prosecution Agreement.
See Note 14 - Commitments and Contingencies of the Combined Notes to
Consolidated Financial Statements for additional information;
• Higher net unrealized and realized losses on NDT funds;
• Lower capacity revenue;
• Reduction in load due to COVID-19 at Generation;
• Higher nuclear outage days;
• Higher storm costs related to the
• Higher credit loss expense that includes the impacts of COVID-19 at
Generation, PECO, Pepco, and DPL;
• COVID-19 direct costs;
• Unfavorable weather conditions at PECO and ACE; and
• Lower allowed electric distribution ROE due to a decrease in treasury rates.
The decreases were partially offset by:
• Higher mark-to-market gains;
• Lower operating and maintenance expense primarily due to previous cost
management programs and lower contracting costs at Generation;
• The approval of the New Jersey ZEC program in the second quarter of 2019;
• An income tax settlement at Generation; and
• Regulatory rate increases at BGE 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.
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The following tables provide a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and six months endedJune 30, 2020 compared to the same period in 2019. Three Months Ended June 30, 2020 2019 Earnings per Earnings per (All amounts in millions after tax) Diluted Share Diluted Share Net Income Attributable to Common Shareholders$ 521 $ 0.53 $ 484 $ 0.50 Mark-to-Market Impact of Economic Hedging Activities (net of taxes of$18 and$22 , respectively) (51 ) (0.05 ) 68 0.07 Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of$275 and$28 , respectively)(a) (305 ) (0.31 ) 52 0.05 Asset Impairments (net of taxes of$7 and$1 , respectively)(b) 19 0.02 1 - Plant Retirements and Divestitures (net of taxes of$2 and$37 , respectively)(c) 7 0.01 (24 ) (0.02 ) Cost Management Program (net of taxes of$3 and$1 , respectively)(d) 6 0.01 6 0.01 Litigation Settlement Gain (net of taxes of$7 ) - - (19 ) (0.02 ) Change in Environmental Liabilities (net of taxes of$0 ) 1 - - - COVID-19 Direct Costs (net of taxes of$10 )(e) 27 0.03 - - Deferred Prosecution Agreement Payments (net of taxes of$0 )(f) 200 0.20 - - Income Tax-Related Adjustments (entire amount represents tax expense) 5 0.01 - - Noncontrolling Interests (net of taxes of$20 and$3 , respectively)(g) 104 0.11 15 0.02
Adjusted (non-GAAP) Operating Earnings
583 $ 0.60
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Six Months Ended June 30,
2020 2019
Earnings per Earnings per
(All amounts in millions after tax) Diluted Share Diluted Share
Net Income Attributable to Common
Shareholders $ 1,103 $ 1.13 $ 1,391 $ 1.43
Mark-to-Market Impact of Economic
Hedging Activities (net of taxes of
$50 and $34 , respectively) (146 ) (0.15 ) 98 0.10
Unrealized (Gains) Losses Related to
NDT Fund Investments (net of taxes of
$130 and $133 , respectively)(a) 180 0.18 (142 ) (0.15 )
Asset Impairments (net of taxes of $7
and $2 , respectively)(b) 21 0.02 6 0.01
Plant Retirements and Divestitures
(net of taxes of $6 and $32 ,
respectively)(c) 20 0.02 (4 ) -
Cost Management Program (net of taxes
of $6 and $7 , respectively)(d) 17 0.02 16 0.02
Litigation Settlement Gain (net of
taxes of $7 ) - - (19 ) (0.02 )
Change in Environmental Liabilities
(net of taxes of $0 ) 1 - - -
COVID-19 Direct Costs (net of taxes of
$10 )(e) 27 0.03 - -
Deferred Prosecution Agreement
Payments (net of taxes of $0 )(f) 200 0.20 - -
Income Tax-Related Adjustments (entire
amount represents tax expense) 4 - - -
Noncontrolling Interests (net of taxes
of $10 and $15 , respectively)(g) (40 ) (0.04 ) 82 0.08
Adjusted (non-GAAP) Operating Earnings
1,429$ 1.47 __________ Note: Amounts may not sum due to rounding. Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2020 and 2019 ranged from 26.0% to 29.0%. UnderIRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 47.4% and 35.1% for the three months endedJune 30, 2020 and 2019, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 41.9% and 48.4% for the six months endedJune 30, 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) Reflects an impairment at ComEd related to the acquisition of transmission
assets and the impairment of certain wind assets at Generation.
(c) In 2019, primarily reflects net realized gains related to
fund investments in conjunction with the
gain on the sale of certain wind assets, partially offset by accelerated
depreciation and amortization expenses associated with the early retirement
of the TMI nuclear facility. In 2020, primarily reflects accelerated
depreciation and amortization expenses associated with the early retirement
of certain fossil sites.
(d) Primarily represents reorganization costs related to cost management
programs.
(e) 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.
(f) Reflects the payments that ComEd will make under the Deferred Prosecution
Agreement. See Note 14 - Commitments and Contingencies of the Combined Notes
to Consolidated Financial Statements for additional information.
(g) 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 2020 Transactions and Developments Deferred Prosecution Agreement OnJuly 17, 2020 , ComEd entered into a Deferred Prosecution Agreement (DPA) with theU.S. Attorney's Office for the Northern District of Illinois (USAO) to resolve the USAO's investigation into ComEd's lobbying activities in theState 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 theIllinois 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 theUnited 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. 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 2020. See Note 2 - 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 Rate (Decrease) (Decrease) Effective
Registrant/Jurisdiction Filing Date Increase Increase Approved ROE Approval Date Date
ComEd -
8.91 % December 4, 2019 January 1,
2019 2020
December 5,
2019 July 16,
DPL - Maryland (Electric) (amended 17 12 9.60 % July 14, 2020 2020
April 23,
2020)
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Pending Distribution Base Rate Case Proceedings
Requested Revenue
Requirement
(Decrease)
Registrant/Jurisdiction Filing Date Increase Requested ROE Expected Approval Timing
ComEd -
(11 ) 8.38 % Fourth quarter of 2020
(Electric)
BGE - Maryland
(Electric and Natural May 15, 2020 235 10.1 % Fourth quarter of 2020
Gas)
Pepco - District of May 30, 2019
Columbia (Electric) (amended June 1, 136 9.7 % Fourth quarter of 2020
2020)
DPL - Delaware (Natural February 21,
Gas) 2020 (amended 9 10.3 % First quarter of 2021
March 17, 2020)
DPL - Delaware March 6, 2020
(Electric) (amended April 24 10.3 % Second quarter of 2021
16, 2020)
Transmission Formula Rates
Transmission Formula Rate (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and
ACE). ComEd's, PECO's, BGE's, Pepco's, DPL's and ACE's transmission rates are
each established based on a FERC -approved formula. ComEd, BGE, Pepco, DPL and
ACE are required to file an annual update to the FERC -approved formula on or
before May 15 and PECO is required to file on or before May 31 , with the
resulting rates effective on June 1 of the same year. The annual update for
ComEd, BGE, DPL and ACE is based on prior year actual costs and current year
projected capital additions (initial year revenue requirement). The annual
update for PECO is based on prior year actual costs and current year projected
capital additions, accumulated depreciation, and accumulated deferred income
taxes. The annual update for Pepco is based on prior year actual costs and
current year projected capital additions, accumulated depreciation, depreciation
and amortization expense and accumulated deferred income taxes. The update for
ComEd, BGE, DPL and ACE also reconciles any differences between the revenue
requirement in effect beginning June 1 of the prior year and actual costs
incurred for that year (annual reconciliation). The update for PECO and Pepco
also reconciles any differences between the actual costs and actual revenues for
the calendar year (annual reconciliation).
For 2020, the following total increases/(decreases) were included in ComEd's,
PECO's, BGE's, Pepco's, DPL's and ACE's electric transmission formula rate
filings:
Initial Revenue Total Revenue
Requirement Requirement
Increase Annual Reconciliation Increase Allowed Return
Registrant (Decrease) Decrease (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 %
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Sales of Customer Accounts Receivable OnApril 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 5 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. 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 2019 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 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") 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 Russian Suspension Agreement 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 theU.S. government has expressed interest in continuing the limitations on Russian imports by renegotiating the Russian Suspension Agreement.The Working Group report should be viewed as policy recommendations that may be implemented by executive agencies, congress and or regulatory bodies. Negotiations between the DOC and the Russians on an extension of the Russian Suspension Agreement are in progress at this time, and may result in a reduction in the amount of uranium that can be imported fromRussia , which may have the effect of reducing the diversity of supply available to Exelon for uranium, enrichment and conversion services purchases. Exelon and Generation cannot currently predict the outcome of the policy changes recommended by theWorking Group . 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 ofJune 30, 2020 , the percentage of expected generation hedged for the Mid-Atlantic, Midwest,New York andERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively. 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 149
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2020 through 2024 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 results of operations, cash flows and financial positions. 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. Environmental Legislative and Regulatory Developments Air Quality Mercury and Air Toxics Standards Rule (MATS). OnDecember 16, 2011 , theEPA signed a final rule, known as MATS, to reduce emissions of hazardous air pollutants from power plants. MATS requires coal-fired power plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. InApril 2014 , theU.S. Court of Appeals for the D.C. Circuit issued a decision upholding MATS in its entirety. On appeal, theU.S. Supreme Court decided inJune 2015 that theEPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate power plant emissions of hazardous air pollutants, but did not vacate MATS. In 2016, theEPA issued a supplemental finding responding to theU.S. Supreme Court's decision; theEPA concluded that, after considering costs, it remained appropriate and necessary to regulate hazardous air pollutants from power plants. OnMay 22, 2020 , however, theEPA reversed course, publishing a final rule revoking the "appropriate and necessary" finding underpinning MATS. A coal mining company filed a lawsuit in theU.S. D.C. Circuit court seeking vacatur of MATS based onEPA 'sMay 22, 2020 ruling. OnJune 22, 2020 , Exelon and two other entities filed a motion to intervene in that lawsuit to defend MATS, and onJuly 21, 2020 , they separately filed a lawsuit in the D.C. Circuit court challenging theEPA 'sMay 22, 2020 rescission of the appropriate and necessary finding underpinning MATS. The Clean Power Plan and Affordable Clean Energy Rule. TheEPA 's 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants underClean Air Act Section 111(d). The CPP's carbon pollution limits could be met through changes to the electric generation system, including shifting generation from higher-emitting units to lower- or zero-emitting units, as well as the development of new or expanded zero-emissions generation. InJuly 2019 , theEPA published its final the Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines for existing fossil-fired power plants based on heat rate improvement measures that could be achieved within the fence line of individual plants. Exelon, together with a coalition of other electric utilities, filed a lawsuit in theU.S. Court of Appeals for the D.C. Circuit onSeptember 6, 2019 , challenging the Affordable Clean Energy rule as unlawful. This lawsuit has been consolidated with separate challenges to the Affordable Clean Energy rule filed by various states, non-governmental organizations, and business coalitions. Employees InJune 2020 , Generation, ComEd, and DPL ratified or extended CBAs as follows: • Generation ratified its CBA withSPFPA Local 238 , which covers 122 security officers at Quad Cities. The CBA expires in 2023. • ComEd extended its CBA withIBEW Local 15 to 2022, which covers 80 employees in theSystem Services Group .
• DPL ratified its CBAs with IBEW Locals 1238 and 1307, which together cover
857 employees. Both CBAs expire in 2024.
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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. AtJune 30, 2020 , the Registrants' critical accounting policies and estimates had not changed significantly fromDecember 31, 2019 . See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Critical Accounting Policies and Estimates in the Registrants' 2019 Form 10-K for further information. Results of Operations by Registrant 151 --------------------------------------------------------------------------------
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Generation
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 Six Months Ended (Unfavorable)
June 30, (Unfavorable) June 30, Favorable
2020 2019 Variance 2020 2019 Variance
Operating revenues $ 3,880 $ 4,210 $ (330 ) $ 8,613 $ 9,506 $ (893 )
Purchased power and fuel
expense 1,942 2,292 350 4,646 5,497 851
Revenues net of purchased
power and fuel expense 1,938 1,918 20 3,967 4,009 (42 )
Other operating expenses
Operating and maintenance 1,189 1,266 77 2,451 2,484 33
Depreciation and
amortization 300 409 109 604 814 210
Taxes other than income
taxes 116 129 13 246 264 18
Total other operating
expenses 1,605 1,804 199 3,301 3,562 261
Gain on sales of assets and
businesses 12 33 (21 ) 12 33 (21 )
Operating income 345 147 198 678 480 198
Other income and
(deductions)
Interest expense, net (87 ) (116 ) 29 (197 ) (227 ) 30
Other, net 602 171 431 (168 ) 601 (769 )
Total other income and
(deductions) 515 55 460 (365 ) 374 (739 )
Income before income taxes 860 202 658 313 854 (541 )
Income taxes 329 78 (251 ) (59 ) 301 360
Equity in losses of
unconsolidated affiliates (2 ) (6 ) 4 (4 ) (13 ) 9
Net income 529 118 411 368 540 (172 )
Net income (loss)
attributable to
noncontrolling interests 53 10 43 (153 ) 68 (221 )
Net income attributable to
membership interest $ 476 $ 108 $ 368 $
521
Three Months EndedJune 30, 2020 Compared to Three Months EndedJune 30, 2019 . Net income attributable to membership interest increased$368 million by primarily due to: • Higher net unrealized and realized gains on NDT funds;
• Higher mark-to-market gains; and
• Lower operating and maintenance expense primarily due to lower contracting
costs.
The increases were partially offset by:
• Lower capacity revenue;
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• Reduction in load due to COVID-19;
• COVID-19 direct costs; and
• Higher credit loss expense that includes the impacts of COVID-19.
Six Months EndedJune 30, 2020 Compared to Six Months EndedJune 30, 2019 . Net income attributable to membership interest increased$49 million by primarily due to: • Higher mark-to-market gains; • Lower operating and maintenance expense primarily due to previous cost management programs and lower contracting costs;
• The approval of the New Jersey ZEC program in the second quarter of 2019; and
• An income tax settlement. The increases were partially offset by: • Higher net unrealized and realized losses on NDT funds;
• Lower capacity revenue;
• Reduction in load due to COVID-19;
• Higher nuclear outage days;
• COVID-19 direct costs; and
• Higher credit loss expense that includes the impacts of COVID-19.
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 4 - 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. 153 --------------------------------------------------------------------------------
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Generation
For the three and six months endedJune 30, 2020 compared to 2019, RNF by region were as follows. See Note 4 - 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
Six Months Ended
June 30 ,
2020 2019 Variance % Change 2020 2019 Variance % Change
Mid-Atlantic(a) $ 525 $ 652 $ (127 ) (19.5 )% $ 1,092 $ 1,334 $ (242 ) (18.1 )%
Midwest(b) 703 730 (27 ) (3.7 )% 1,427 1,500 (73 ) (4.9 )%
New York 246 253 (7 ) (2.8 )% 440 519 (79 ) (15.2 )%
ERCOT 97 79 18 22.8 % 177 154 23 14.9 %
Other Power
Regions 157 134 23 17.2 % 312 292 20 6.8 %
Total electric
revenues net of
purchased power
and fuel
expense 1,728 1,848 (120 ) (6.5 )% 3,448 3,799 (351 ) (9.2 )%
Mark-to-market
gains (losses) 85 (74 ) 159 214.9 % 218 (102 ) 320 313.7 %
Other 125 144 (19 ) (13.2 )% 301 312 (11 ) (3.5 )%
Total revenue
net of
purchased power
and fuel
expense $ 1,938 $ 1,918 $ 20 1.0 % $ 3,967 $ 4,009 $ (42 ) (1.0 )%
_________(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 Six Months Ended
June 30, June 30,
Supply Source
(GWhs) 2020 2019 Variance % Change 2020 2019 Variance % Change
Nuclear
Generation(a)
Mid-Atlantic 13,167 14,075 (908 ) (6.5 )% 25,951 29,155 (3,204 ) (11.0 )%
Midwest 23,860 23,996 (136 ) (0.6 )% 47,458 47,729 (271 ) (0.6 )%
New York 6,389 6,677 (288 ) (4.3 )% 12,562 13,579 (1,017 ) (7.5 )%
Total Nuclear
Generation 43,416 44,748 (1,332 ) (3.0 )% 85,971 90,463 (4,492 ) (5.0 )%
Fossil and
Renewables
Mid-Atlantic 707 915 (208 ) (22.7 )% 1,560 1,865 (305 ) (16.4 )%
Midwest 268 328 (60 ) (18.3 )% 656 719 (63 ) (8.8 )%
New York 1 1 - - % 2 2 - - %
ERCOT 3,251 3,066 185 6.0 % 6,263 6,144 119 1.9 %
Other Power
Regions 2,603 2,514 89 3.5 % 6,110 5,654 456 8.1 %
Total Fossil and
Renewables 6,830 6,824 6 0.1 % 14,591 14,384 207 1.4 %
Purchased Power
Mid-Atlantic 3,730 2,557 1,173 45.9 % 9,672 5,123 4,549 88.8 %
Midwest 236 250 (14 ) (5.6 )% 524 538 (14 ) (2.6 )%
ERCOT 1,255 1,213 42 3.5 % 2,246 2,255 (9 ) (0.4 )%
Other Power
Regions 11,303 11,116 187 1.7 % 23,469 23,684 (215 ) (0.9 )%
Total Purchased
Power 16,524 15,136 1,388 9.2 % 35,911 31,600 4,311 13.6 %
Total Supply/Sales
by Region(c)
Mid-Atlantic(b) 17,604 17,547 57 0.3 % 37,183 36,143 1,040 2.9 %
Midwest(b) 24,364 24,574 (210 ) (0.9 )% 48,638 48,986 (348 ) (0.7 )%
New York 6,390 6,678 (288 ) (4.3 )% 12,564 13,581 (1,017 ) (7.5 )%
ERCOT 4,506 4,279 227 5.3 % 8,509 8,399 110 1.3 %
Other Power
Regions 13,906 13,630 276 2.0 % 29,579 29,338 241 0.8 %
Total Supply/Sales
by Region 66,770 66,708 62 0.1 % 136,473 136,447 26 - %
_________(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 three and six months ended
Increase/ Three Months Ended
Increase/ Six Months Ended
(Decrease) June 30, 2020 (Decrease) 2020
Mid-
revenue revenue
• decreased revenue due • decreased revenue due
to permanent cease of to permanent cease of
generation operations at generation operations at
Three Mile Island in the Three Mile Island in the
third quarter of 2019 third quarter of 2019
• decreased load due to • decreased load due to
COVID-19 COVID-19
• lower realized energy • lower realized energy
prices, partially offset prices, partially offset
by by
• increased ZEC revenues • increased ZEC revenues
due to decreased nuclear due to the approval of
outage days at Salem the NJ ZEC program in the
second quarter of 2019
Midwest (27 ) • decreased capacity (73 ) • decreased capacity
revenue revenue
• decreased load due to • decreased load due to
COVID-19 COVID-19
• lower realized energy • lower realized energy
prices prices
New York (7 ) • decreased load due to (79 ) • decreased load due to
COVID-19 COVID-19
• lower realized energy • lower realized energy
prices, partially offset prices
by • increased nuclear
• increased capacity outage days
revenues
ERCOT 18 • higher portfolio 23 • higher portfolio
optimization, partially optimization partially
offset by offset by
• decreased load due to • decreased load due to
COVID-19 COVID-19
Other Power Regions 23 • higher portfolio 20 • higher portfolio
optimization, partially optimization, partially
offset by offset by
• decreased capacity • decreased capacity
revenue revenue
• decreased load due to • decreased load due to
COVID-19 COVID-19
Mark-to-market(a) 159 • gains on economic 320 • gains on economic
hedging activities of $85 hedging activities of
million in 2020 compared $218 million in 2020
to losses of $74 million compared to losses of
in 2019 $102 million in 2019
Other (19 ) • decreased revenue (11 ) • decreased revenue
related to the energy related to the energy
efficiency business efficiency business
Total $ 20 $ (42 )
_________(a) See Note 11 - Derivative Financial Instruments for additional information on
mark-to-market gains (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. Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Nuclear fleet capacity factor 95.4 % 95.1 % 94.7 % 96.1 % Refueling outage days 92 56 186 130 Non-refueling outage days - 28 11 28 The changes in Operating and maintenance expense consisted of the following: Three Months Ended Six Months Ended June 30, June 30, 2020 2020 Increase (Decrease) Increase (Decrease) Litigation Settlements $ 26 $ 26 COVID-19 Direct Costs 23 23 Nuclear refueling outage costs, including the co-owned Salem plants 12 54 Credit loss expense(a) 12 17 Asset Impairments 9 5 Pension and non-pension postretirement benefits expense (4 ) (9 ) Accretion expense (5 ) (15 ) Other (9 ) (4 ) Travel and Entertainment (11 ) (12 ) Plant retirements and divestitures (13 ) 69 Corporate allocations (16 ) (27 ) Labor, other benefits, contracting and materials(b) (101 ) (160 ) Increase in operating and maintenance expense $ (77 ) $ (33 )
_________
(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 and lower labor costs resulting from previous
cost management programs.
Depreciation and amortization expense for the three and six months endedJune 30, 2020 compared to the same period in 2019 decreased primarily due to the permanent cease of generation operations atThree Mile Island in the third quarter of 2019. Taxes other than income taxes for the three and six months endedJune 30, 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 three and six months endedJune 30, 2020 compared to the same period in 2019 decreased primarily due to Generation's gain on sale of certain wind assets in the second quarter of 2019. Interest Expense for the three and six months endedJune 30, 2020 compared to the same period in 2019 decreased primarily due to the maturity of long-term debt in the first and second quarter of 2020. 157 --------------------------------------------------------------------------------
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Other, net for the three months endedJune 30, 2020 compared to the same period in 2019 increased and for the six months endedJune 30, 2020 compared to the same period in 2019 decreased due to activity associated with NDT funds as described in the table below: Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Net unrealized (losses) gains on NDT funds(a)$ 452 $ (98 ) $ (253 ) $ 182 Net realized gains on sale of NDT funds(a) 3 193 58 222 Interest and dividend income on NDT funds(a) 19 36 46 61 Contractual elimination of income tax expense(b) 134 34 (43 ) 120 Other (6 ) 6 24 16 Total other, net$ 602 $ 171 $ (168 ) $ 601 _________
(a) Unrealized gains (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.
Effective income tax rates were 38.3% and 38.6% for the three months endedJune 30, 2020 and 2019, respectively. Generation's effective income tax rates were (18.8)% and 35.2% for the six months endedJune 30, 2020 and 2019, respectively. The change primarily reflects one-time tax settlements. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information Net income attributable to noncontrolling interests for the three months endedJune 30, 2020 compared to the same period in 2019 increased primarily due to higher net gains on NDT fund investments for CENG and for the six months endedJune 30, 2020 compared to the same period in 2019 decreased primarily due to unrealized losses on NDT fund investments for CENG. 158 --------------------------------------------------------------------------------
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ComEd
Results of Operations - ComEd
Three Months Ended Favorable Six Months Ended Favorable
June 30, (Unfavorable) June 30, (Unfavorable)
2020 2019 Variance 2020 2019 Variance
Operating revenues $ 1,417 $ 1,351 $ 66 $ 2,856 $ 2,759 $ 97
Operating expenses
Purchased power expense 464 407 (57 ) 951 892 (59 )
Operating and
maintenance 536 305 (231 ) 853 626 (227 )
Depreciation and
amortization 274 257 (17 ) 547 508 (39 )
Taxes other than income
taxes 71 71 - 146 148 2
Total operating expenses 1,345 1,040 (305 ) 2,497 2,174 (323 )
Gain on sales of assets - - - - 3 (3 )
Operating income 72 311 (239 ) 359 588 (229 )
Other income and
(deductions)
Interest expense, net (98 ) (89 ) (9 ) (192 ) (178 ) (14 )
Other, net 11 10 1 22 19 3
Total other income and
(deductions) (87 ) (79 ) (8 ) (170 ) (159 ) (11 )
(Loss) income before
income taxes (15 ) 232 (247 ) 189 429 (240 )
Income taxes 46 46 - 82 85 3
Net (loss) income $ (61 ) $ 186 $ (247 ) $ 107 $ 344 $ (237 )
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019 .
Net income decreased $247 million as compared to the same period in 2019,
primarily due to payments that ComEd will make under the Deferred Prosecution
Agreement, an impairment charge resulting from acquisition of transmission
assets, and distribution formula rate timing. See Note 14 - Commitments and
Contingencies of the Combined Notes to Consolidated Financial Statements for
additional information related to the Deferred Prosecution Agreement.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Net
income decreased $237 million as compared to the same period in 2019, primarily
due to payments that ComEd will make 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 14 - 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:
Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020
Increase (Decrease) Increase (Decrease)
Electric distribution $ - $ 21
Transmission (4 ) (12 )
Energy efficiency 6 19
2 28
Regulatory required programs 64 69
Total increase $ 66 $ 97
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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 a change to the electric distribution formula rate pursuant to 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 for the three months endedJune 30, 2020 compared to the same period in 2019 remained relatively consistent. Electric distribution revenue increased during the six months endedJune 30, 2020 as compared to the same period in 2019, primarily 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 2 - 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. Transmission revenue decreased for the three and six months endedJune 30, 2020 as compared to the same period in 2019, primarily due to the impact of decreased peak load partially offset by higher fully recoverable costs. See Note 2 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 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 and six months endedJune 30, 2020 as compared to the same period in 2019, primarily due to the increased regulatory asset amortization. See Depreciation and amortization expense discussions below and Note 2 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 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 and fuel 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 but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to electricity, ZEC and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. ComEd recovers electricity, ZEC and REC procurement costs from customers without mark-up. See Note 4 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation. The increase of$57 million and$59 million for the three and six months endedJune 30, 2020 compared to the same period in 2019, respectively, in Purchased power expense is offset in Operating revenues as part of regulatory required programs. 160 --------------------------------------------------------------------------------
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The changes in Operating and maintenance expense consisted of the following:
Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020
Increase (Decrease) (Decrease) Increase
Deferred Prosecution Agreement payments(a) $ 200 $ 200
Storm-related costs 9 2
BSC costs 6 16
Pension and non-pension postretirement benefits expense 2 4
Labor, other benefits, contracting and materials 1 (9 )
Other(b) 10 13
228 226
Regulatory required programs(c) 3 1
Total increase $ 231 $ 227
__________(a) See Note 14 - Commitments and Contingencies of the Combined Notes to
Consolidated Financial Statements for additional information.
(b) Primarily reflects impairment charge related to acquisition of transmission
assets.
(c) 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. During the three and six months ended
the timing of regulatory cost recovery. An equal and offsetting amount has
been recognized in Operating revenues for the period presented.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020
Increase Increase
Depreciation and amortization(a) $ 14 $ 28
Regulatory asset amortization(b) 3 11
Total increase $ 17 $ 39
_________
(a) Reflects ongoing capital expenditures.
(b) Includes amortization of ComEd's energy efficiency formula rate regulatory
asset.
Effective income tax rate were (306.7)% and 19.8% for the three months endedJune 30, 2020 and 2019, respectively, and 43.4% and 19.8% for the six months endedJune 30, 2020 and 2019. 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. 161 --------------------------------------------------------------------------------
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PECO
Results of Operations - PECO
Three Months Ended Favorable Six Months Ended Favorable
June 30, (Unfavorable) June 30, (Unfavorable)
2020 2019 Variance 2020 2019 Variance Operating revenues
$ 681 $ 655 $ 26$ 1,493 $ 1,554 $ (61 ) Operating expenses Purchased power and fuel expense 216 191 (25 ) 499 520 21 Operating and maintenance 275 199 (76 ) 492 424 (68 ) Depreciation and amortization 88 83 (5 ) 173 164 (9 ) Taxes other than income taxes 39 37 (2 ) 78 79 1 Total operating expenses 618 510 (108 ) 1,242 1,187 (55 ) Operating income 63 145 (82 ) 251 367 (116 ) Other income and (deductions) Interest expense, net (36 ) (33 ) (3 ) (71 ) (67 ) (4 ) Other, net 5 3 2 7 7 - Total other income and (deductions) (31 ) (30 ) (1 ) (64 ) (60 ) (4 ) Income before income taxes 32 115 (83 ) 187 307 (120 ) Income taxes (7 ) 13 20 9 37 28 Net income$ 39 $ 102 $ (63 ) $ 178 $ 270 $ (92 ) Three Months EndedJune 30, 2020 Compared to Three Months EndedJune 30, 2019 . Net income decreased by$63 million primarily due to higher storm costs due toJune 2020 storms and an increase in credit loss expense including the impacts of COVID-19, partially offset by favorable weather conditions. Six Months EndedJune 30, 2020 Compared to Six Months EndedJune 30, 2019 . Net income decreased by$92 million primarily due to unfavorable weather conditions, higher storm costs due toJune 2020 storms, and an increase in credit loss expense including the impacts of COVID-19. The changes in Operating revenues consisted of the following: Three Months Ended Six Months Ended June 30, 2020 June 30, 2020 Increase (Decrease) Increase (Decrease) Electric Gas Total Electric Gas Total Weather$ 3 $ 8 $ 11 $ (23 ) $ (13 ) $ (36 ) Volume 3 (3 ) - (4 ) (6 ) (10 ) Pricing (2 ) 1 (1 ) 6 5 11 Transmission - - - 2 - 2 Other (4 ) - (4 ) (4 ) (1 ) (5 ) - 6 6 (23 ) (15 ) (38 ) Regulatory required programs 20 - 20 27 (50 ) (23 ) Total increase (decrease)$ 20 $ 6 $ 26 $ 4 $ (65 ) $ (61 ) 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 endedJune 30, 2020 compared to the same period in 2019, Operating revenues related to weather increased by the impact of favorable weather conditions in PECO's service territory. During the six months ended 162 --------------------------------------------------------------------------------
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June 30, 2020 compared to the same period in 2019, Operating revenues related to weather decreased by 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 three and six months endedJune 30, 2020 compared to the same period in 2019 and normal weather consisted of the following: Heating and Cooling Degree-Days % Change Three Months Ended June 30, 2020 2019 Normal From 2019 2020 vs. Normal Heating Degree-Days 568 270 432 110.4 % 31.5 % Cooling Degree-Days 376 425 386 (11.5 )% (2.6 )% Six Months EndedJune 30 , Heating Degree-Days 2,557 2,702 2,850 (5.4 )% (10.3 )% Cooling Degree-Days 376 427 387 (11.9 )% (2.8 )% Volume. Electric volume, exclusive of the effects of weather, for the three months endedJune 30, 2020 compared to the same period in 2019, increased on a net basis due to an increase in usage for residential customers partially offset by a decrease for commercial and industrial customers due to COVID-19. Residential volumes were further increased by customer growth. Electric volume, exclusive of the effects of weather, for the six months endedJune 30, 2020 compared to the same period in 2019, decreased on a net basis due to a decrease in usage for commercial and industrial customers partially offset by an increase in usage for residential customers due to COVID-19. Volumes further decreased as a result of the impact of energy efficiency initiatives across all customer classes partially offset by increases due to customer growth. Natural gas volume for the three and six months endedJune 30, 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 partially offset by increased usage for the residential natural gas class due to COVID-19. Electric Retail Deliveries to Three Months Ended Weather - Six Months Ended Weather - Customers (in June 30, Normal June 30, Normal GWhs) 2020 2019 % Change % Change(b) 2020 2019 % Change % Change(b) Residential 3,143 2,821 11.4 % 8.4 % 6,397 6,462 (1.0 )% 3.3 % Small commercial & industrial 1,571 1,823 (13.8 )% (12.9 )% 3,476 3,889 (10.6 )% (7.7 )% Large commercial & industrial 3,181 3,769 (15.6 )% (14.7 )% 6,602 7,340 (10.1 )% (9.2 )% Public authorities & electric railroads 112 182 (38.5 )% (38.5 )% 263 377 (30.2 )% (30.4 )% Total electric retail deliveries(a) 8,007 8,595 (6.8 )% (7.1 )% 16,738 18,068 (7.4 )% (4.8 )% As of June 30, Number of Electric Customers 2020 2019 Residential 1,501,259 1,486,973 Small commercial & industrial 154,016 153,387 Large commercial & industrial 3,096 3,105 Public authorities & electric railroads 10,119 9,733 Total 1,668,490 1,653,198 163
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PECO
_________(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.
Natural Gas
Deliveries to Three Months Ended Weather - Six Months Ended Weather -
Customers (in June 30, Normal June 30, Normal
mmcf) 2020 2019 % Change % Change(b) 2020 2019 % Change % Change(b)
Residential 6,464 3,351 92.9 % 9.3 % 23,746 24,569 (3.3 )% 1.2 %
Small commercial
& industrial 2,054 4,040 (49.2 )% (46.0 )% 10,863 14,684 (26.0 )% (10.8 )%
Large commercial
& industrial 3 17 (82.4 )% (30.0 )% 12 36 (66.7 )% (18.0 )%
Transportation 5,148 5,719 (10.0 )% (16.0 )% 12,283 13,692 (10.3 )% (8.0 )%
Total natural
gas retail
deliveries(a) 13,669 13,127 4.1 % (13.7 )% 46,904 52,981 (11.5 )% (4.3 )%
As of June 30,
Number of Natural Gas Customers 2020 2019
Residential 489,201 483,657
Small commercial & industrial 44,189 43,953
Large commercial & industrial 6 2
Transportation 719 737
Total 534,115 528,349
_________(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.
Pricing for the three months endedJune 30, 2020 compared to the same period in 2019 remained relatively consistent. Pricing for the six months endedJune 30, 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 aFERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three and six months endedJune 30, 2020 compared to the same period in 2019 remained relatively consistent. 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 but impact Operating revenues related to supplied electricity and natural gas. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. PECO recovers electricity, natural gas and REC procurement costs from customers without mark-up. Other revenue primarily includes revenue related to late payment charges. Other revenues decreased for the three and six months endedJune 30, 2020 , compared to the same period in 2019, as PECO temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. See Note 4- Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation. 164 --------------------------------------------------------------------------------
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PECO
The increase of$25 million and decrease of$21 million for the three and six months endedJune 30, 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: Three Months Ended Six Months Ended June 30, 2020 June 30, 2020 Increase (Decrease) (Decrease) Increase Storm-related costs(a) $ 61 $ 53 Credit loss expense(b) 18 19 Labor, other benefits, contracting and materials 1 (5 ) Pension and non-pension postretirement benefits expense (1 ) (1 ) Other (3 ) 2 Total increase $ 76 $ 68 __________
(a) Reflects increased storm costs due to the
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended June Six Months Ended
30, 2020 June 30, 2020
Increase Increase (Decrease)
Depreciation and amortization(a) $ 5 $ 10
Regulatory asset amortization - (1 )
Total increase $ 5 $ 9
__________(a) Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Effective Income Tax Rates were (21.9)% and 11.3% for the three months endedJune 30, 2020 and 2019, respectively, and 4.8% and 12.1% for the six months endedJune 30, 2020 and 2019. 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. 165 -------------------------------------------------------------------------------- Table of Contents BGE Results of Operations - BGE Three Months Ended (Unfavorable) Six Months Ended (Unfavorable) June 30, Favorable June 30, Favorable 2020 2019
Variance 2020 2019 Variance Operating revenues
$ 616 $ 649 $ (33 ) $ 1,554 $ 1,625 $ (71 ) Operating expenses Purchased power and fuel expense 194 208 14 483 570 87 Operating and maintenance 187 182 (5 ) 376 372 (4 ) Depreciation and amortization 129 117 (12 ) 272 252 (20 ) Taxes other than income taxes 63 62 (1 ) 132 131 (1 ) Total operating expenses 573 569 (4 ) 1,263 1,325 62 Operating income 43 80 (37 ) 291 300 (9 ) Other income and (deductions) Interest expense, net (32 ) (29 ) (3 ) (64 ) (58 ) (6 ) Other, net 6 5 1 10 11 (1 ) Total other income and (deductions) (26 ) (24 ) (2 ) (54 ) (47 ) (7 ) Income before income taxes 17 56 (39 ) 237 253 (16 ) Income taxes (22 ) 11 33 18 47 29 Net income$ 39 $ 45 $ (6 )$ 219 $ 206 $ 13 Three Months EndedJune 30, 2020 Compared to Three Months EndedJune 30, 2019 . Net income remained relatively consistent. Six Months EndedJune 30, 2020 Compared to Six Months EndedJune 30, 2019 . Net income increased by$13 million primarily due to higher natural gas and electric distribution rates that became effectiveDecember 2019 . The changes in Operating revenues consisted of the following: Three Months Ended Six Months Ended June 30, 2020 June 30, 2020 Increase (Decrease) Increase (Decrease) Electric Gas Total Electric Gas Total Distribution$ 1 $ 6 $ 7 $ 10 $ 35 $ 45 Transmission (17 ) - (17 ) (11 ) - (11 ) Other (5 ) (3 ) (8 ) (2 ) (4 ) (6 ) (21 ) 3 (18 ) (3 ) 31 28 Regulatory required programs (14 ) (1 ) (15 ) (77 ) (22 ) (99 ) Total (decrease) increase$ (35 ) $ 2 $ (33 ) $ (80 ) $ 9 $ (71 ) 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. 166 --------------------------------------------------------------------------------
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BGE
As of June 30,
Number of Electric Customers 2020 2019
Residential 1,185,718 1,171,815
Small commercial & industrial 114,118 113,982
Large commercial & industrial 12,416 12,275
Public authorities & electric railroads 264 264 Total
1,312,516 1,298,336
As of June 30,
Number of Natural Gas Customers 2020 2019
Residential 643,745 634,939
Small commercial & industrial 38,255 38,164 Large commercial & industrial 6,079 5,991 Total
688,079 679,094
Distribution Revenue increased for the three and six months ended June 30, 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 . See Note 2 - Regulatory Matters of the Combined Notes to Consolidated
Financial Statements for additional information.
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 three and six
months ended June 30, 2020 , compared to the same period in 2019, primarily due
to the settlement agreement of ongoing transmission-related income tax
regulatory liabilities. See Note 2 - Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information.
Other revenue includes revenue related to mutual assistance, administrative
charges, off-system sales, and late payment charges. Other revenues decreased
for the three and six months ended June 30, 2020 , compared to the same period in
2019, as BGE temporarily suspended customer disconnections for non-payment 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 but impact
Operating revenues related to supplied electricity and natural gas. Drivers of
Operating revenues related to commodity procurement costs and participation in
customer choice programs are fully offset by their impact on Purchased power and
fuel expense. BGE recovers electricity, natural gas and procurement costs from
customers with a slight mark-up.
See Note 4 - Segment Information of the Combined Notes to the Consolidated
Financial Statements for the presentation of BGE's revenue disaggregation.
The decrease of $14 million and decrease of $87 million for the three and six
months ended June 30, 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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BGE
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020
Increase (Decrease) Increase (Decrease)
Credit loss expense $ 7 $ 6
BSC costs 1 4
Labor, other benefits, contracting and materials 1 3
Storm-related costs - (5 )
Pension and non-pension postretirement benefits expense (1 ) (1 )
Other (2 ) (2 )
6 5
Regulatory required programs (1 ) (1 )
Total increase $ 5 $ 4
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020
Increase Increase (Decrease)
Depreciation and amortization(a) $ 9 $ 21
Regulatory required programs 3 (1 )
Total increase $ 12 $ 20
_________(a) Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Effective income tax rates were (129.4)% and 19.6% for the three months endedJune 30, 2020 and 2019, respectively, and 7.6% and 18.6% for the six months endedJune 30, 2020 and 2019. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 - Regulatory Matters 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. 168 --------------------------------------------------------------------------------
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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. See the Results of Operations for Pepco, DPL and
ACE for additional information.
Three Months Ended Six Months Ended
June 30, June 30,
2020 2019 (Unfavorable)Favorable Variance 2020 2019 (Unfavorable)Favorable Variance
PHI $ 94 $ 106 $ (12 ) $ 202 $ 223 $ (21 )
Pepco 57 64 (7 ) 109 119 (10 )
DPL 19 30 (11 ) 64 83 (19 )
ACE 18 14 4 31 24 7
Other(a) - (2 ) 2 (2 ) (3 ) 1
_________(a) Primarily includes eliminating and consolidating adjustments, PHI's corporate
operations, shared service entities and other financing and investing
activities.
Three Months EndedJune 30, 2020 Compared to Three Months EndedJune 30, 2019 . Net Income decreased by$12 million primarily due to an increase in credit loss expense including the impacts of COVID-19 and an increase in various expenses, partially offset by higher electric distribution rates primarily at ACE. Six Months EndedJune 30, 2020 Compared to Six Months EndedJune 30, 2019 . Net Income decreased by$21 million primarily due to an increase in credit loss expense including the impacts of COVID-19, unfavorable weather conditions in ACE's service territory and an increase in various expenses, partially offset by higher electric distribution rates primarily at ACE. 169 --------------------------------------------------------------------------------
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Pepco
Results of Operations - Pepco
Three Months Ended June 30, (Unfavorable) Favorable Six Months Ended June 30, (Unfavorable) Favorable
2020 2019 Variance 2020 2019 Variance
Operating revenues $ 494 $ 531 $ (37 ) $ 1,039 $ 1,106 $ (67 )
Operating expenses
Purchased power expense 138 144 6 303 331 28
Operating and maintenance 119 111 (8 ) 231 230 (1 )
Depreciation and amortization 92 93 1 186 186 -
Taxes other than income taxes 87 90 3 179 182 3
Total operating expenses 436 438 2 899 929 30
Operating income 58 93 (35 ) 140 177 (37 )
Other income and (deductions)
Interest expense, net (34 ) (34 ) - (68 ) (68 ) -
Other, net 9 7 2 18 14 4
Total other income and (deductions) (25 ) (27 ) 2 (50 ) (54 ) 4
Income before income taxes 33 66 (33 ) 90 123 (33 )
Income taxes (24 ) 2 26 (19 ) 4 23
Net income $ 57 $ 64 $ (7 ) $ 109 $ 119 $ (10 )
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019 .
Net income decreased by $7 million primarily due to an increase in credit loss
expense including the impacts of COVID-19.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Net
income decreased by $10 million primarily due to an increase in credit loss
expense including the impacts of COVID-19.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2020 Six Months Ended June 30, 2020
Increase (Decrease) Increase (Decrease)
Volume $ 2 $ 4
Distribution 2 3
Transmission (26 ) (28 )
Other (1 ) (2 )
(23 ) (23 )
Regulatory required programs (14 ) (44 )
Total decrease $ (37 ) $ (67 )
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.
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Pepco
Volume, exclusive of the effects of weather, remained relatively consistent for
three and six months ended
As of June 30,
Number of Electric Customers 2020 2019
Residential 825,000 811,985
Small commercial & industrial 53,809 54,194
Large commercial & industrial 22,467 22,155
Public authorities & electric railroads 168 155 Total
901,444 888,489
Distribution Revenue increased for the three and six months ended June 30, 2020
compared to the same period in 2019, due to higher electric distribution rates
in Maryland that became effective in August 2019 .
Transmission Revenues. 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 revenues decreased for the three and six
months ended June 30, 2020 compared to the same period in 2019, primarily due to
the settlement agreement of ongoing transmission-related income tax regulatory
liabilities. See Note 2 - 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 three and six months ended June 30, 2020 , compared to the same
period in 2019, as Pepco temporarily suspended customer disconnections for
non-payment 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, but impact Operating revenues
related to supplied electricity. Drivers of Operating revenues related to
commodity and REC procurement costs and participation in customer choice
programs are fully offset by their impact on Purchased power expense. Pepco
recovers electricity and REC procurement costs from customers with a slight
mark-up.
See Note 4 - Segment Information of the Combined Notes to Consolidated Financial
Statements for the presentation of Pepco's revenue disaggregation.
The decrease of $6 million and $28 million for the three and six months ended
June 30, 2020 compared to the same period 2019, respectively, in Purchased power
expense is fully offset in Operating revenues as part of regulatory required
programs.
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Pepco
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended Six Months Ended June 30,
June 30, 2020 2020
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting and materials $ 5 $ 12
Credit loss expense 8 7
Storm-related costs 1 (1 )
Pension and non-pension postretirement benefits expense (1 ) (3 )
BSC and PHISCO costs - (3 )
Expiration of lease arrangement (4 ) (8 )
Other (3 ) (4 )
6 -
Regulatory required programs 2 1
Total increase $ 8 $ 1
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020
Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a) $ 4 $ 9
Regulatory required programs (5 ) (9 )
Total decrease $ (1 ) $ -
_________(a) Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Effective income tax rates were (72.7)% and 3.0% for the three months ended June
30, 2020 and 2019, respectively, and (21.1)% and 3.3% for the six months ended
June 30, 2020 and 2019, respectively. The change is primarily related to the
settlement agreement of ongoing transmission-related income tax regulatory
liabilities. See Note 2 - Regulatory Matters and 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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DPL
Results of Operations - DPL
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 (Unfavorable)Favorable Variance 2020 2019 (Unfavorable)Favorable Variance
Operating revenues $ 267 $ 287 $ (20 ) $ 617 $ 667 $ (50 )
Operating expenses
Purchased power and fuel expense 107 107 - 249 271 22
Operating and maintenance 92 77 (15 ) 172 160 (12 )
Depreciation and amortization 47 45 (2 ) 94 91 (3 )
Taxes other than income taxes 17 14 (3 ) 32 28 (4 )
Total operating expenses 263 243 (20 ) 547 550 3
Operating income 4 44 (40 ) 70 117 (47 )
Other income and (deductions)
Interest expense, net (15 ) (15 ) - (31 ) (30 ) (1 )
Other, net 2 5 (3 ) 5 7 (2 )
Total other income and (deductions) (13 ) (10 ) (3 ) (26 ) (23 ) (3 )
(Loss) income before income taxes (9 ) 34 (43 ) 44 94 (50 )
Income taxes (28 ) 4 32 (20 ) 11 31
Net income $ 19 $ 30 $ (11 ) $ 64 $ 83 $ (19 )
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019 .
Net income decreased by $11 million primarily due to an increase in credit loss
expense including the impacts of COVID-19 and an increase in various expenses,
partially offset by favorable weather conditions in DPL's Delaware service
territory.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Net
income decreased by $19 million primarily due to an increase in credit loss
expense including the impacts of COVID-19 and an increase in various expenses.
The changes in Operating revenues consisted of the following:
Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ 1 $ 6 $ 7 $ (5 ) $ - $ (5 )
Volume - (3 ) (3 ) 1 (3 ) (2 )
Distribution - - - 2 3 5
Transmission (25 ) - (25 ) (22 ) - (22 )
Other (1 ) - (1 ) (2 ) (1 ) (3 )
(25 ) 3 (22 ) (26 ) (1 ) (27 )
Regulatory required programs (1 ) 3 2 (22 ) (1 ) (23 )
Total (decrease) increase $ (26 ) $ 6 $ (20 ) $ (48 ) $ (2 ) $ (50 )
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 customers in Maryland are not impacted by abnormal weather or usage
per customer, they are impacted by changes in the number of customers.
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DPL
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 three
months ended June 30, 2020 compared to the same period in 2019, Operating
revenues related to weather increased due to the impact of favorable weather
conditions in DPL's Delaware service territory. During the six months ended June
30, 2020 compared to the same period in 2019, Operating revenues related to
weather decreased due to the impact of unfavorable weather conditions in DPL's
Delaware 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 DPL's Delaware electric service territory and a 30-year period
in DPL's Delaware natural gas service territory. The changes in heating and
cooling degree days in DPL's Delaware service territory for the three and six
months ended June 30, 2020 compared to same period in 2019 and normal weather
consisted of the following:
Delaware Electric
Service Territory % Change
Three Months Ended June
30, 2020 2019 Normal 2020
vs. 2019 2020 vs. Normal
Heating Degree-Days 606 300 467 102.0 % 29.8 %
Cooling Degree-Days 299 386 334 (22.5 )% (10.5 )%
% Change
Six Months Ended June
30, 2020 2019 Normal 2020 vs. 2019 2020 vs. Normal
Heating Degree-Days 2,609 2,822 2,980 (7.5 )% (12.4 )%
Cooling Degree-Days 299 386 335 (22.5 )% (10.7 )%
Delaware Natural Gas
Service Territory % Change
Three Months Ended June
30, 2020 2019 Normal 2020 vs. 2019 2020 vs. Normal
Heating Degree-Days 606 300 486 102.0 % 24.7 %
% Change
Six Months Ended June
30, 2020 2019 Normal 2020vs. 2019 2020 vs. Normal Heating Degree-Days 2,609 2,822 2,984 (7.5 )%
(12.6 )%
Volume, exclusive of the effects of weather, remained relatively consistent for
the three and six months ended
Electric Retail
Deliveries to Three Months Ended Six Months Ended
Delaware June 30, June 30,
Customers (in Weather - Normal Weather - Normal
GWhs) 2020 2019 % Change % Change(b) 2020 2019 % Change % Change(b)
Residential 703 652 7.8 % 4.6 % 1,446 1,503 (3.8 )% 1.4 %
Small commercial
& industrial 274 306 (10.5 )% (10.9 )% 570 626 (8.9 )% (6.4 )%
Large commercial
& industrial 810 866 (6.5 )% (6.1 )% 1,633 1,676 (2.6 )% (1.7 )%
Public
authorities &
electric
railroads 9 9 - % 4.0 % 17 17 - % 3.0 %
Total electric
retail
deliveries(a) 1,796 1,833 (2.0 )% (3.0 )% 3,666 3,822 (4.1 )% (1.2 )%
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DPL
As of June 30 ,
Number of Total Electric Customers (
470,788 465,423
Small commercial & industrial 61,958
61,552
Large commercial & industrial 1,402
1,398
Public authorities & electric railroads 612 619 Total 534,760 528,992 _________
(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 Three Months Ended Six Months Ended Delaware June 30, June 30, Customers (in Weather - Normal Weather - Normal mmcf) 2020 2019 % Change % Change(b) 2020 2019 % Change % Change(b) Residential 1,168 741 57.6 % (11.8 )% 4,815 5,348 (10.0 )% (2.8 )% Small commercial & industrial 557 566 (1.6 )% (35.0 )% 2,228 2,586 (13.8 )% (7.4 )% Large commercial & industrial 411 442 (7.0 )% (7.0 )%
863 965 (10.6 )% (10.6 )% Transportation 1,472 1,475 (0.2 )%
(8.0 )% 3,580 3,693 (3.1 )% (0.9 )%
Total natural
gas
deliveries(a) 3,608 3,224 11.9 % (14.1 )% 11,486 12,592 (8.8 )% (3.8 )%
As of June 30,
Number of Delaware Natural Gas Customers 2020 2019 Residential
126,245 124,325
Small commercial & industrial 9,914 9,907
Large commercial & industrial 17 18
Transportation 159 158
Total 136,335 134,408
__________(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 six months endedJune 30, 2020 compared to the same period in 2019 primarily due to higher natural gas distribution rates due to the Gas Distribution System Improvement Charge (DSIC) fully implemented in the first quarter 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 years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the three and six months endedJune 30, 2020 compared to the same period in 2019 primarily due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 - 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 three and six months endedJune 30, 2020 compared to the same period in 2019, as DPL temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. 175 --------------------------------------------------------------------------------
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DPL
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, but impact Operating revenues related to supplied electricity.
Drivers of Operating revenues related to commodity and REC procurement costs and
participation in customer choice programs are fully offset by their impact on
Purchased power expense. DPL recovers electricity and REC procurement costs from
customers with a slight mark-up and natural gas costs from customers without
mark-up.
See Note 4 - Segment Information for the Combined Notes to Consolidated
Financial Statements for the presentation of DPL's revenue disaggregation.
The decrease of $22 million for the six months ended June 30, 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.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting and materials $ 8 $ 8
Credit loss expense 7 5
Storm-related costs 2 2
Pension and non-pension postretirement benefits expense (1 ) (2 )
BSC and PHISCO costs - (2 )
Other (5 ) (2 )
11 9
Regulatory required programs 4 3
Total increase $ 15 $ 12
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended Six Months Ended
June 30, 2020 June 30, 2020
Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a) $ 3 $ 5
Regulatory required programs (1 ) (2 )
Total increase $ 2 $ 3
_________(a) Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Effective income tax rates were 311.1% and 11.8% for the three months endedJune 30, 2020 and 2019, respectively, and (45.5)% and 11.7% for the six months endedJune 30, 2020 and 2019, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 - Regulatory Matters and 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. 176 --------------------------------------------------------------------------------
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ACE
Results of Operations - ACE
Three Months Ended June 30, (Unfavorable) Favorable Six Months Ended June 30, (Unfavorable) Favorable
2020 2019 Variance 2020 2019 Variance
Operating revenues $ 256 $ 274 $ (18 ) $ 532 $ 547 $ (15 )
Operating expenses
Purchased power expense 130 131 1 259 270 11
Operating and maintenance 82 74 (8 ) 160 155 (5 )
Depreciation and amortization 44 40 (4 ) 86 71 (15 )
Taxes other than income taxes 2 1 (1 ) 4 2 (2 )
Total operating expenses 258 246 (12 ) 509 498 (11 )
Gain on sale of assets - - - 2 - 2
Operating (loss) income (2 ) 28 (30 ) 25 49 (24 )
Other income and (deductions)
Interest expense, net (15 ) (15 ) - (29 ) (28 ) (1 )
Other, net 2 1 1 3 4 (1 )
Total other income and (deductions) (13 ) (14 ) 1 (26 ) (24 ) (2 )
Income before income taxes (15 ) 14 (29 ) (1 ) 25 (26 )
Income taxes (33 ) - 33 (32 ) 1 33
Net income $ 18 $ 14 $ 4 $ 31 $ 24 $ 7
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019 .
Net income increased by $4 million primarily due to higher electric distribution
rates that became effective in April 2020 partially offset by lower commercial
and industrial usage.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019 . Net
income increased by $7 million primarily due to higher electric distribution
rates that became effective in April 2019 and April 2020 , partially offset by
unfavorable weather conditions in ACE's service territory, lower commercial and
industrial usage and increased depreciation and amortization expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2020 Six Months Ended June 30, 2020
(Decrease) Increase (Decrease) Increase
Weather $ (1 ) $ (5 )
Volume (4 ) (6 )
Distribution 5 20
Transmission (24 ) (18 )
Other (1 ) (2 )
(25 ) (11 )
Regulatory required programs 7 (4 )
Total decrease $ (18 ) $ (15 )
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 six months ended June 30, 2020 compared to same period in 2019 due to
the impact of unfavorable weather conditions in ACE's service territory.
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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 and six months ended June
30, 2020 compared to same period in 2019 consisted of the following:
Heating and Cooling
Degree-Days % Change
Three Months Ended June
30, 2020 2019 Normal 2020
vs. 2019 2020 vs. Normal
Heating Degree-Days 613 380 541 61.3 % 13.3 %
Cooling Degree-Days 312 351 304 (11.1 )% 2.6 %
% Change
Six Months Ended June
30, 2020 2019 Normal 2020 vs. 2019 2020 vs. Normal
Heating Degree-Days 2,561 2,886 3,034 (11.3 )% (15.6 )%
Cooling Degree-Days 312 351 305 (11.1 )% 2.3 %
Volume, exclusive of the effects of weather, decreased for the three and six
months ended June 30, 2020 compared to the same period in 2019, primarily due to
lower commercial and industrial usage.
Electric Retail
Deliveries to Three Months Ended Weather - Six Months Ended Weather -
Customers (in June 30, Normal % June 30, 2020 Normal %
GWhs) 2020 2019 % Change Change(b) 2020 2019 % Change Change(b)
Residential 850 804 5.7 % 6.5 % 1,660 1,713 (3.1 )% 1.3 %
Small
commercial &
industrial 276 314 (12.1 )% (12.8 )% 570 624 (8.7 )% (6.4 )%
Large commercial
& industrial 702 872 (19.5 )% (19.3 )% 1,437 1,662 (13.5 )% (12.7 )%
Public
authorities &
electric
railroads 11 11 - % 2.8 % 24 24 - % (0.9 )%
Total electric
retail
deliveries(a) 1,839 2,001 (8.1 )% (7.9 )% 3,691 4,023 (8.3 )% (5.7 )%
As of June 30,
Number of Electric Customers 2020 2019
Residential 496,668 492,940
Small commercial & industrial 61,468 61,416
Large commercial & industrial 3,327 3,464
Public authorities & electric railroads 687 672 Total
562,150 558,492
_________
(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 three and six months endedJune 30, 2020 compared to the same period in 2019 primarily due to higher electric distribution rates that became effective inApril 2019 andApril 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. Transmission revenue decreased for the three and six months endedJune 30, 2020 compared to the same period in 2019, primarily due to settlement agreement for 178 --------------------------------------------------------------------------------
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ongoing transmission-related income tax regulatory liabilities. See Note 2 -
Regulatory Matters of the Combined Notes to Consolidated Financial Statements
for additional information.
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 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, but impact Operating revenues related to supplied electricity.
Drivers of Operating revenues related to commodity, REC and ZEC procurement
costs and participation in customer choice programs are fully offset by their
impact on Purchased power expense. ACE recovers electricity, REC and ZEC
procurement costs from customers without mark-up.
See Note 4 - Segment Information of the Combined Notes to Consolidated Financial
Statements for the presentation of ACE's revenue disaggregation.
The decrease of $1 million and $11 million for three and six months ended June
30, 2020 compared to the same period in 2019 , respectively, 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 Six Months Ended
June 30, 2020 June 30, 2020
Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting and materials $ 6 $ 9
Storm-related costs (1 ) (1 )
BSC and PHISCO costs - (1 )
Credit loss expense(a) 7 6
Other (3 ) (8 )
9 5
Regulatory required programs (1 ) -
Total increase $ 8 $ 5
_________(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 a rider mechanism. An equal and offsetting amount has been recognized
in Operating revenues.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended Six Months Ended June 30,
June 30, 2020 2020
Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a) $ 3 $ 12
Regulatory asset amortization (2 ) (1 )
Regulatory required programs 3 4
Total increase $ 4 $ 15
_________(a) Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Gain on sale of assets for the six months ended
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Effective income tax rates were 220.0% and 0.0% for the three months ended June
30, 2020 and 2019, respectively, 3,200.0% and 4.0% for the six months ended June
30, 2020 and 2019, respectively. The change is primarily related to the
settlement agreement of ongoing transmission-related income tax regulatory
liabilities. See Note 2 - Regulatory Matters and 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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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$10.7 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 5 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sale of customer accounts receivable. Exelon Corporate, Generation, and the Utility Registrants continued to issue commercial paper during the second quarter of 2020. 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 other postretirement benefit 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. Despite disruptions in the financial markets due to COVID-19, the Registrants have been able to fund their liquidity needs to date. As ofDecember 31, 2019 , Exelon had approximately$4.0 billion of long-term debt that matures in 2020, excluding project financings and floating rate long-term debt. Of this, as ofJune 30, 2020 , Exelon has redeemed or refinanced approximately$3.4 billion that is maturing in 2020. The remaining amount of$0.6 billion on Exelon's and Generation's Consolidated Balance Sheet matures in the fourth quarter of 2020. To date in 2020, the Registrants have been able to execute their expected debt issuances and have issued long-term debt of$5.1 billion , of which$4.0 billion was issued in the period of April to July of 2020. The Registrants accelerated the timing of a number of planned debt issuances resulting in the$4.0 billion issued in the period of April to July of 2020 and the Registrants have now completed their planned long-term debt issuances for the 2020 year. 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 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 7 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information. 181
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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 fund investments 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. 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, the NRC must approve an exemption in order for the plant's owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s) without reimbursement from or access to the NDT funds. The ultimate costs for spent fuel management may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under theDOE reimbursement agreements. As ofJune 30, 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 12 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. Refer to Note 16 - Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on credit facilities. Cash Flows from Operating Activities (All Registrants) General 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 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2019 Form 10-K for additional information of regulatory and legal proceedings and proposed legislation. 182
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The following table provides a summary of the change in cash flows from
operating activities for the six months ended
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