EXELON CORPORATION 
Exelon
Executive Overview Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE. Exelon has eleven reportable segments consisting of Generation's five reportable segments (Mid-Atlantic, Midwest,New York ,ERCOT and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL and ACE. During the first quarter of 2019, due to a change in economics in ourNew England region, Generation changed the way that information is reviewed by the CODM. TheNew England region is no longer regularly reviewed as a separate region by the CODM nor presented separately in any external information presented to third parties. Information for theNew England region is reviewed by the CODM as part of Other Power Regions. See Note 1 - Significant Accounting Policies and Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments. Exelon's consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management's Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 , and is separately filed byExelon, Generation , ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the year endedDecember 31, 2018 compared to the year endedDecember 31, 2017 , refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2018-Form 10-K, which was filed with theSEC onFebruary 8, 2019 . 60
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Financial Results of Operations GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the year endedDecember 31, 2019 compared to the same period in 2018 and 2017. For additional information regarding the financial results for the years endedDecember 31, 2019 and 2018 see the discussions of Results of Operations by Registrant. Favorable (unfavorable) 2019 vs. 2018 Favorable (unfavorable) 2019 2018(a) variance 2017(a) 2018 vs. 2017 variance Exelon$ 2,936 $ 2,005 $ 931$ 3,779 $ (1,774 ) Generation 1,125 370 755 2,710 (2,340 ) ComEd 688 664 24 567 97 PECO 528 460 68 434 26 BGE 360 313 47 307 6 PHI 477 393 84 355 38 Pepco 243 205 38 198 7 DPL 147 120 27 121 (1 ) ACE 99 75 24 77 (2 ) Other(b) (242 ) (195 ) (47 ) (594 ) 399 __________
(a) Exelon's, PHI's and Pepco's amounts have been revised to reflect the
correction of an error related to Pepco's decoupling mechanism. See Note 1 -
Significant Accounting Policies of the Combined Notes to Consolidated
Financial Statements for additional information.
(b) Primarily includes eliminating and consolidating adjustments, Exelon's
corporate operations, shared service entities and other financing and
investing activities.
Year EndedDecember 31, 2019 Compared to Year EndedDecember 31, 2018 . Net income attributable to common shareholders increased by$931 million and diluted earnings per average common share increased to$3.01 in 2019 from$2.07 in 2018 primarily due to: • Higher net unrealized and realized gains on NDT funds; • Decreased accelerated depreciation and amortization due to the early retirement of theOyster Creek nuclear facility inSeptember 2018 and TMI inSeptember 2019 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO in 2018; • Decreased Operating and maintenance expense at Generation which includes the impacts of previous cost management programs, lower
pension and OPEB costs and increased NEIL insurance distributions;
• A benefit associated with the remeasurement of the TMI ARO in the first
quarter of 2019 and the annual nuclear ARO update in the third quarter
of 2019;
• Decreased nuclear outage days;
• Lower mark-to-market losses;
• Regulatory rate increases at PECO, BGE, Pepco, DPL, and ACE;
• Increased electric distribution, energy efficiency and transmission
earnings at ComEd;
• Decreased storms costs at PECO and BGE; and
• Research and development income tax benefits.
The increases were partially offset by;
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• Lower realized energy prices;
• Lower capacity prices;
• Unfavorable weather conditions at PECO, DPL and ACE; and
• Unfavorable volume at PECO.
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 table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year endedDecember 31, 2019 as compared to 2018 and 2017: For the Years Ended December 31, 2019 2018(a) 2017(a) (All amounts in millions after Earnings per Earnings per Earnings per tax) Diluted Share Diluted Share Diluted Share Net Income Attributable to Common Shareholders$ 2,936 $ 3.01 $ 2,005 $ 2.07 $ 3,779 $ 3.98 Mark-to-Market Impact of Economic Hedging Activities (net of taxes of$66 ,$89 and$68 , respectively) 197 0.20 252 0.26 107 0.11 Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of$269 ,$289 and$286 , respectively)(b) (299 ) (0.31 ) 337 0.35 (318 ) (0.34 ) Amortization of Commodity Contract Intangibles (net of taxes of$22 ) - - - - 34 0.04 PHI Merger and Integration Costs (net of taxes of$2 and$25 , respectively) - - 3 - 40 0.04 Merger Commitments (net of taxes of$137 ) - - - - (137 ) (0.14 ) Asset Impairments (net of taxes of$56 ,$13 and$204 , respectively)(c) 123 0.13 35 0.04 321 0.34 Plant Retirements and Divestitures (net of taxes of$9 ,$181 , and$134 , respectively)(d) 118 0.12 512 0.53 207 0.22 Cost Management Program (net of taxes of$17 ,$16 , and$21 , respectively)(e) 51 0.05 48 0.05 34 0.04 Asset Retirement Obligation (net of taxes of$9 ,$7 , and$1 , respectively)(f) (84 ) (0.09 ) 20 0.02 (2 ) - Vacation Policy Change (net of taxes of$21 ) - - - - (33 ) (0.03 ) Change in Environmental Liabilities (net of taxes of$8 ,$0 , and$17 , respectively) 20 0.02 (1 ) - 27 0.03 Bargain Purchase Gain (net of taxes of$0 ) - - - - (233 ) (0.25 ) Gain on Deconsolidation of Business (net of taxes of$83 ) - - - - (130 ) (0.14 ) Gain on Contract Settlement (net of taxes of$20 )(g) - - (55 ) (0.06 ) - - Litigation Settlement Gain (net of taxes of$7 ) (19 ) (0.02 ) - - - - Income Tax-Related Adjustments (entire amount represents tax expense)(h) 5 0.01 (22 ) (0.02 ) (1,330 ) (1.41 ) Noncontrolling Interests (net of taxes of$26 ,$24 , and$24 , respectively)(i) 90 0.09 (113 ) (0.12 ) 114 0.12 Adjusted (non-GAAP) Operating Earnings$ 3,139 $ 3.22 $ 3,021 $ 3.12 $ 2,480 $ 2.61 __________ Note: Amounts may not sum due to rounding. Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2019 and 2018 ranged from 26.0 percent to 29.0 percent. 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 funds were 47.3 percent and 46.2 percent for the years endedDecember 31, 2019 and 2018, respectively. 63
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(a) Net Income Attributable to Common Shareholders and Adjusted (non-GAAP)
Operating Earnings have been revised to reflect the correction of an error
related to Pepco's decoupling mechanism. See Note 1 - Significant Accounting
Policies of the Combined Notes to Consolidated Financial Statements for
additional information.
(b) 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.
(c) In 2018, primarily reflects the impairment of certain wind projects at
Generation. In 2019, primarily reflects the impairment of equity method
investments in certain distributed energy companies. The impact of such
impairment net of noncontrolling interest is $0.02 .
(d) In 2018, primarily reflects accelerated depreciation and amortization
expenses and one-time charges associated with Generation's decision to early
retire the
a remeasurement of the Oyster Creek ARO, partially offset by a gain
associated with Generation's sale of its electrical contracting business. In
2019, primarily reflects accelerated depreciation and amortization expenses
associated with the early retirement of the TMI nuclear facility and certain
fossil sites and the loss on the sale of
offset by net realized gains related to
a net benefit associated with remeasurements of the TMI ARO and a gain on the
sale of certain wind assets.
(e) Primarily represents severance and reorganization costs related to cost
management programs.
(f) In 2018, reflects an increase at Pepco related primarily to asbestos
identified at its
to Generation's annual nuclear ARO update for non-regulatory units.
(g) Represents the gain on the settlement of a long-term gas supply agreement at
Generation.
(h) In 2018, reflects an adjustment to the remeasurement of deferred income taxes
as a result of the TCJA. In 2019, primarily reflects the adjustment to
deferred income taxes due to changes in forecasted apportionment.
(i) Represents elimination from Generation's results of the noncontrolling
interests related to certain exclusion items. In 2018, primarily related to
the impact of unrealized losses on NDT fund investments for CENG units. In
2019, primarily related to the impact of unrealized gains on NDT fund
investments and the impact of the Generation's annual nuclear ARO update for
CENG units, partially offset by the impairment of certain equity investments
in distributed energy companies.
Significant 2019 Transactions and Developments
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 results of operations, cash flows and
financial position.
The following tables show the Utility Registrants' completed and pending
distribution base rate case proceedings in 2019. See Note 3 - Regulatory Matters
of the Combined Notes to Consolidated Financial Statements for additional
information on other regulatory proceedings.
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Completed Utility Distribution Base Rate Case Proceedings
Requested Approved
Revenue Revenue
Requirement Requirement Rate
Filing Increase Increase Effective
Registrant/Jurisdiction Date (Decrease) (Decrease) Approved ROE Approval Date Date
ComEd -
January 1,
(Electric) 2018 $ (23 ) $ (24 ) 8.69 % December 4, 2018 2019
ComEd - Illinois April 8, January 1,
(Electric) 2019 $ (6 ) $ (17 ) 8.91 % December 4, 2019 2020
PECO - Pennsylvania March 29, January 1,
(Electric) 2018 $ 82 $ 25 N/A December 20, 2018 2019
June 8,
2018
(amended
BGE - Maryland October January 4,
(Natural Gas) 12, 2018) $ 61 43 9.8 % January 4, 2019 2019
May 24,
2019
(amended
BGE - Maryland December December
(Electric) 17, 2019) $ 74 $ 18 9.7 %
May 24,
2019
(amended
BGE - Maryland (Natural December December
Gas) 17, 2019) $ 59 $ 45 9.75 %
August
21, 2018
(amended
ACE - New Jersey November April 1,
(Electric) 19, 2018) $ 122 $ 70 9.6 % March 13, 2019 2019
January
15, 2019
(amended
Pepco - Maryland May 16, August 13,
(Electric) 2019) $ 27 $ 10.3 9.6 % Pending Distribution Base Rate Case Proceedings
Requested Revenue
Requirement
Registrant/Jurisdiction Filing Date Increase Requested ROE Expected Approval Timing
May 30, 2019
(amended
Pepco - District of September 16,
Columbia (Electric) 2019) $ 160 10.3 % Fourth quarter of 2020
DPL - Maryland December 5,
(Electric) 2019 $ 19 10.3 % Third quarter of 2020
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Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's,
Pepco's, DPL's and ACE's 2019 annual electric transmission formula rate updates.
Initial Revenue Total Revenue
Requirement Annual Reconciliation Requirement Allowed Return
Registrant Increase/(Decrease) (Decrease)/Increase Increase/(Decrease) on Rate Base Allowed ROE
ComEd $ 21 $ (16 ) $ 5 8.21 % 11.50 %
BGE (10 ) (23 ) (19 ) 7.35 % 10.50 %
Pepco 15 11 26 7.75 % 10.50 %
DPL 17 (1 ) 16 7.14 % 10.50 %
ACE 11 (2 ) 9 7.79 % 10.50 %
PECO Transmission Formula Rate
On May 1, 2017 , PECO filed a request with FERC seeking approval to update its
transmission rates and change the manner in which PECO's transmission rate is
determined from a fixed rate to a formula rate. The formula rate will be updated
annually to ensure that under this rate customers pay the actual costs of
providing transmission services. PECO's initial formula rate filing included a
requested increase of $22 million to PECO's annual transmission revenue
requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder
for being a member of a RTO. On June 27, 2017 , FERC issued an Order accepting
the filing and suspending the proposed rates until December 1, 2017 , subject to
refund, and set the matter for hearing and settlement judge procedures.
On December 5, 2019 , FERC issued an Order accepting without modification the
settlement agreement filed by PECO and other parties in July 2019 . The
settlement results in an increase of approximately $14 million with a return on
rate base of 7.62% compared to PECO's initial formula rate filing and allows for
an ROE of 10.35%, inclusive of a 50 basis point adder for being a member of the
RTO. The settlement did not have a material impact on PECO's 2017, 2018, or 2019
annual transmission revenue requirements. PECO will update its rates in 2020 and
refund estimated overcollections totaling approximately $28 million related to
the amounts billed under the proposed rates in effect since 2017.
Pursuant to the transmission formula rate request discussed above, PECO made its
annual formula rate updates in May 2018 and 2019, which included a decrease of
$6 million and an increase of $8 million , respectively, to the annual
transmission revenue requirement. The updated transmission formula rates were
effective on June 1, 2018 and 2019, respectively, subject to refund.
Cost Management Programs
Exelon continues to be committed to managing its costs. On October 31, 2019 ,
Exelon announced additional annual cost savings of approximately $100 million ,
at Generation, to be achieved by 2022. These actions are in response to the
continuing economic challenges confronting Generation's business, necessitating
continued focus on cost management through enhanced efficiency and productivity.
FERC Order on the PJM MOPR
On December 19, 2019 , FERC issued an order directing PJM to extend the MOPR to
include new and existing resources, including nuclear, that receive state
subsidies, effective as of PJM's next capacity auction. Unless Illinois and New
Jersey can implement an FRR program in their PJM zones, the MOPR will apply to
Generation's nuclear plants in those states receiving ZEC benefits, resulting in
higher offers for those units that may not clear the capacity market. On January
21, 2020 , Exelon, PJM and a number of other entities submitted individual
requests for rehearing. Exelon is currently working with PJM and other
stakeholders to pursue the FRR option but cannot predict whether the legislative
and regulatory changes can be implemented prior to the next capacity auction in
PJM. If Generation's state-supported nuclear plants in PJM or NYISO are
subjected to the MOPR without compensation under an FRR or similar program, it
could have a material adverse impact on Exelon's and Generation's financial
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statements. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Early Plant RetirementsOyster Creek . Generation permanently ceased generation operations atOyster Creek onSeptember 17, 2018 . OnJuly 31, 2018 , Generation entered into an agreement withHoltec International and its wholly owned subsidiary,Oyster Creek Environmental Protection, LLC , for the sale and decommissioning of Oyster Creek. The sale was completed onJuly 1, 2019 . Exelon and Generation recognized a loss on the sale in the third quarter 2019, which was immaterial. See Note 2 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. ThreeMile Island . Generation permanently ceased operations at TMI onSeptember 20, 2019 . As a result of the decision to early retire TMI, Exelon and Generation recorded a$176 million incremental pre-tax net charge for the year endedDecember 31, 2019 primarily due to accelerated depreciation of the plant assets, partially offset by a benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019.Salem . In 2017, PSEG announced that itsNew Jersey nuclear plants, includingSalem , of which Generation owns a 42.59% ownership interest, were showing increased signs of economic distress, which could lead to an early retirement. PSEG is the operator ofSalem and also has the decision-making authority to retireSalem . In 2018,New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. OnApril 18, 2019 , the NJBPU approved the award of ZECs to Salem Unit 1 and Salem Unit 2. Assuming the continued effectiveness of the New Jersey ZEC program, Generation no longer considersSalem to be at heightened risk for early retirement. Dresden,Byron andBraidwood . Generation's Dresden,Byron andBraidwood nuclear plants inIllinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. TheMay 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions ofByron andBraidwood . Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level. See Note 3 - Regulatory Matters, Note 6 - Early Plant Retirements and Note 9 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. CENG Put Option OnNovember 20, 2019 , Generation received notice of EDF's intention to exercise the put option and sell its 49.99% equity interest in CENG to Generation and the put automatically exercised onJanuary 19, 2020 at the end of the sixty-day advance notice period. Under the terms of the Put Option, the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. Any resulting sale would be subject to the approval of the NYPSC, theFERC and the NRC. The process and regulatory approvals could take one to two years or more to complete. See Note 2 - Mergers, Acquisitions and Dispositions for additional information.Conowingo Hydroelectric Project In connection with Generation's pursuit of a newFERC license for Conowingo, onOctober 29, 2019 , Generation and MDE filed withFERC a Joint Offer of Settlement that would resolve all outstanding issues between the parties, effective upon and subject toFERC's approval and incorporation of the terms into the new license when issued. The financial impact of this settlement, along with other anticipated and prior license commitments, would be recognized over the term of the new 50-year license and is estimated to be, on average,$11 million to$14 million per year, including capital and operating costs. The actual timing and amount of a majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict whenFERC will issue the new license. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.Pacific Gas & Electric Bankruptcy 67
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Generation'sAntelope Valley , a 242 MW solar facility inLancaster, CA , sells all of its output to PG&E through a PPA. OnJanuary 29, 2019 , PG&E filed for protection under Chapter 11 of theU.S. Bankruptcy Code. As ofDecember 31, 2019 , Generation had approximately$725 million and$485 million of net long-lived assets and nonrecourse debt outstanding, respectively, related toAntelope Valley . PG&E's bankruptcy created an event of default forAntelope Valley's nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon's and Generation's Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as ofDecember 31, 2019 . In the first quarter of 2019, Generation assessed and determined thatAntelope Valley's long-lived assets were not impaired. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments ofAntelope Valley's net long-lived assets, which could be material. Generation is monitoring the bankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of the net long-lived assets ofAntelope Valley may not be recoverable. See Note 11 - Asset Impairments and Note 16 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the PG&E bankruptcy. Exelon's Strategy and Outlook for 2020 and Beyond Exelon's value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon's regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition: • The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock. • Generation's competitive businesses provide free cash flow to invest primarily in the utilities and to reduce debt. Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change. Exelon's utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company. Generation's competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation's electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation's customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets. Exelon's financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon's shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. 68
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As part of its strategic business planning process, Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades. Exelon's Board of Directors approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with theMarch 2018 dividend. Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors. Exelon continues to be committed to managing its costs. InNovember 2017 , Exelon announced a commitment for$250 million of cost savings, primarily at Generation, to be achieved by 2020. InNovember 2018 , Exelon announced the elimination of an approximately additional$200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately$150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. InOctober 2019 , Exelon announced additional annual cost savings of approximately$100 million , at Generation, to be achieved by 2022. These actions are in response to the continuing economic challenges confronting Generation's business, necessitating continued focus on cost management through enhanced efficiency and productivity. Growth Opportunities Management continually evaluates growth opportunities aligned with Exelon's businesses, assets and markets, leveraging Exelon's expertise in those areas and offering sustainable returns. Regulated Energy Businesses. The Utility Registrants anticipate investing approximately$26 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately$13 billion by the end of 2023. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Investments and infrastructure development and enhancement programs. Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation's long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development. Other Key Business Drivers and Management Strategies Utility Rates and Rate Proceedings The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants' current and future results of operations, cash flows and financial positions. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings. 69
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Table of Contents Power Markets Price of Fuels The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon's revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development). FERC Inquiry on Resiliency OnAugust 23, 2017 , theDOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is theDOE's recognition that the electricity markets do not currently value the resiliency provided by base-load generation, such as nuclear plants. OnSeptember 28, 2017 , theDOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. OnJanuary 8, 2018 ,FERC issued an order terminating the rulemaking docket that it initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time,FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additionalFERC action to address resiliency would be appropriate.FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties submitted reply comments onMay 9, 2018 , and a few parties submitted further replies. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation. 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, as amended, (the Act) from imports of uranium products, alleging that these imports threaten national security (the Petition). The relief requested would have requiredU.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines for the next 10 years or more. The Act was promulgated byCongress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of theU.S. The Petition alleges that the loss of a viableU.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of theU.S. and the ability of the country to sustain an independent nuclear fuel cycle. OnJuly 18, 2018 , the Secretary announced that the DOC had initiated an investigation in response to the petition. The Secretary submitted a report toPresident Trump onApril 14, 2019 that has not been made public. OnJuly 12, 2019 , the President issued a memorandum indicating that he did not agree with the Secretary's finding that uranium imports threaten to impair the national security ofthe United States , choosing not to impose any trade restrictions at this time.The President found that a fuller analysis of national security considerations with respect to the entire nuclear fuel supply chain is necessary and directed that aUnited States Nuclear Fuel Working Group (Working Group ) be established to develop recommendations for reviving and expanding domestic nuclear fuel production.The Working Group report has not yet been issued and is not expected to be made public.The Working Group is co-chaired by the Assistant to the President for National Security Affairs and the Assistant to the President for Economic Policy. Exelon will monitor and volunteer to provide information to support theWorking Group's efforts. Exelon and Generation cannot currently predict the outcome of theWorking Group report and subsequent actions. Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps OnFebruary 21, 2019 , PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asksFERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity 70
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supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation. Energy Demand Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat load growth in electricity for the Utility Registrants. ComEd, PECO, BGE, Pepco, DPL and ACE are projecting load volumes to increase (decrease) by (0.3)%, (0.7)%, (1.2)%, (0.4)%, (0.5)% and (0.4)%, respectively, in 2020 compared to 2019.Retail Competition Generation's retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output. Hedging Strategy Exelon's policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As ofDecember 31, 2019 , the percentage of expected generation hedged for the Mid-Atlantic, Midwest,New York andERCOT reportable segments is 91%-94% and 61%-64% 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 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 15 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers. Environmental Legislative and Regulatory Developments Exelon was actively involved in theObama Administration's development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants. Through the issuance of a series of Executive Orders (EO),President Trump has initiated review of a number ofEPA and other regulations issued during theObama Administration , with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The 71
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Administration's actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon's and its subsidiaries results of operations and cash flows. In particular, the Administration has targeted existingEPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by theObama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded theInteragency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are the Clean Water Act rule relating to jurisdictional waters of theU.S. , the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds. Air Quality Mercury and Air Toxics Standard Rule (MATS). OnDecember 16, 2011 , theEPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation 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. Numerous entities challenged MATS in theD.C. Circuit Court , and Exelon intervened in support of the rule. InApril 2014 , theD.C. Circuit Court issued an opinion 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 hazardous air pollutants emitted by electric utilities, but did not vacate the rule. OnApril 27, 2017 , theD.C. Circuit Court grantedEPA 's motion to hold the litigation in abeyance, pendingEPA 's review of the MATS rule pursuant toPresident Trump's EO discussed above. Notwithstanding the Court's order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before theD.C. Circuit Court as an intervenor in support of the rule. OnDecember 28, 2018 , theEPA proposed to revoke the "appropriate and necessary" finding underpinning the MATS rule. While the proposal would leave in place the rule, it would leave it vulnerable to future legal challenge. OnFebruary 7, 2019 ,EPA published its Reconsideration of Supplemental Finding and Residual Risk andTechnology Review . After considering public comment,EPA transmitted a final version to theOffice of Management and Budget for review prior to publication. Clean Power Plan. OnApril 28, 2017 , theD.C. Circuit Court issued orders in separate litigation related to theEPA 's actions under the Clean Power Plan (CPP) to amendClean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to theEPA . InJune 2019 ,EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy rule to replace the CPP with less stringent emissions guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants. The Affordable Clean Energy rule is currently being litigated. 2015 Ozone National Ambient Air Quality Standards (NAAQS). OnApril 11, 2017 , theD.C. Circuit Court ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pendingEPA 's further review of the 2015 Rule. OnAugust 23, 2019 , theD.C. Circuit Court upheld the stringency of NAAQS, but remanded certain aspects of its secondary standard toEPA for revision. Primary SO2 National Ambient Air Quality Standards (NAAQS).EPA took final action onApril 17, 2019 to retain the current primary SO2 standard without revision, leaving the standard established in 2010 in effect. Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of Federal legislation, theEPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to theUnited Nations Framework Convention on Climate Change ("UNFCCC" or "Convention"). See ITEM 1. BUSINESS, "Global Climate Change" for additional information. 72
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Table of Contents Water Quality Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All of Generation's power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the regulations. For Generation, those facilities areCalvert Cliffs,Clinton , Dresden,Eddystone ,Fairless Hills , FitzPatrick, Ginna,Gould Street , Handley, Mystic 7, Nine Mile Point Unit 1,Peach Bottom , Quad Cities, andSalem . See ITEM 1. BUSINESS, "Water Quality" for additional information. Clean Water Rule In 2015, theEPA and theUS Army Corps of Engineers , finalized the Clean Water Rule that significantly expanded the definition of the Waters ofthe United States under the Clean Water Act and resulted in increased environmental costs for some projects. OnOctober 22, 2019 , theEPA and theUS Army Corps of Engineers repealed the 2015 Clean Water Rule and restored the definition of the Waters ofthe United States that existed prior to this rule. OnJanuary 23, 2020 , a new final rule was issued by theEPA and theUS Army Corps of Engineers to streamline and clarify the definition of Waters ofthe United States and will be effective sixty days after publication in theFederal Register . This rule represents final action by these government agencies to narrow the scope of Waters ofthe United States that are regulated under the federal Clean Water Act. Solid and Hazardous Waste InOctober 2015 , the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classifies CCR as non-hazardous waste under RCRA. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon's and Generation's financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the new federal regulations for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations. See Note 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters. Other Legislative and Regulatory Developments Illinois Clean Energy Progress Act OnMarch 14, 2019 , the Clean Energy Progress Act was introduced in theIllinois General Assembly to preserveIllinois' clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of PJM's base residual auction process, while utilizing the fixed resource requirement provisions in PJM's tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of Generation's nuclear plants inIllinois , or from new clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state's competitive retail electricity and natural gas markets, including Generation's retail customers. Energy legislation has also been proposed by other stakeholders, including renewable resource developers, environmental advocates, and coal-fueled generators. Exelon and Generation will work with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation. Nuclear Powers Act of 2019 OnApril 12, 2019 , the Nuclear Powers America Act of 2019 was introduced to theUnited States Congress , which expands the current investment tax credit to existing nuclear power plants. The proposed legislation would provide a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be 73
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currently operational and must have applied for an operating license renewal before 2026. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application, or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements. Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation) Generation's ARO associated with decommissioning its nuclear units was$10.5 billion atDecember 31, 2019 . The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios. As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The availability of NDT funds could impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to Generation's current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios. The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions: Decommissioning Cost Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation's nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle. Cost Escalation Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal and other costs. All of the nuclear AROs are adjusted each year for the updated cost escalation factors. Probabilistic Cash Flow Models. Generation's probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The assumed decommissioning scenarios include the following three alternatives: (1) DECON which assumes decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR generally has a 30-year delay prior to onset of decommissioning activities, and (3) SAFSTOR which assumes the nuclear facility is placed and 74
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maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated generally within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible untilDOE acceptance for disposal. The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be influenced by multiple factors including the funding status of the nuclear decommissioning trust fund at the time of shutdown. The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an extended 60-year nuclear license term (regardless of whether such 20-year license extension has been received for each unit), (3) the probability of a second, 20-year license renewal for some nuclear units, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. The successful operation of nuclear plants in theU.S. beyond the initial 40-year license terms has prompted the NRC to consider regulatory and technical requirements for potential plant operations for an 80-year nuclear operating term. As power market and regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates. Generation's probabilistic cash flow models also include an assessment of the timing ofDOE acceptance of SNF for disposal. Generation currently assumesDOE will begin accepting SNF in 2030. The SNF acceptance date assumption is based on management's estimates of the amount of time required forDOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding the estimated date thatDOE will begin accepting SNF, see Note 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. Generation initially recognizes an ARO at fair value and subsequently adjusts it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO as a result of upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, is measured using the average historical CARFR rates used in creating the initial ARO cost layers. If Generation's future nominal cash flows associated with the ARO were to be discounted at current prevailing CARFR, the obligation would increase from approximately$10.5 billion to approximately$13.2 billion . The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO (dollars in millions): Increase (Decrease) to ARO at Change in the CARFR applied to the annual ARO update December 31, 2019 2018 CARFR rather than the 2019 CARFR $ (820 ) 2019 CARFR increased by 50 basis points (390 ) 2019 CARFR decreased by 50 basis points 390 75
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ARO Sensitivities. Changes in the assumptions underlying the ARO could
materially affect the decommissioning obligation. The impact to the ARO of a
change in any one of these assumptions is highly dependent on how the other
assumptions may correspondingly change.
The following table illustrates the effects of changing certain ARO assumptions
while holding all other assumptions constant (dollars in millions):
Increase to ARO at
Change in ARO Assumption December 31, 2019
Cost escalation studies
Uniform increase in escalation rates of 50 basis points $ 2,250
Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 10 percent
910
Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent(a)
550
Shorten each unit's probability weighted operating life assumption by 10 percent(b)
1,570
Extend the estimated date forDOE acceptance of SNF to 2035
350
__________
(a) Excludes any sites in which management has committed to a specific
decommissioning approach.
(b) Excludes any retired sites.
See Note 1 - Significant Accounting Policies, Note 6 - Early Plant Retirements and Note 9 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs.Goodwill (Exelon, ComEd and PHI) As ofDecember 31, 2019 , Exelon's$6.7 billion carrying amount of goodwill consists of$2.6 billion at ComEd,$4 billion at PHI and immaterial amounts at Generation and DPL. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. ComEd has a single operating segment and reporting unit. PHI's operating segments and reporting units are Pepco, DPL and ACE. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd's goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI's goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of$2.1 billion ,$1.4 billion and$0.5 billion , respectively. See Note 12 - Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. Application of the goodwill impairment test requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's and ACE's businesses and the fair value of debt. In applying the second step, if needed, management must estimate the fair value of specific assets and liabilities of the reporting unit. While the annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's or PHI's goodwill, which could be material. Based on the results of the 76
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last annual quantitative goodwill tests performed as ofNovember 1, 2016 andNovember 1, 2018 for ComEd and PHI, respectively, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to fail the first step of their respective impairment tests. See Note 1 - Significant Accounting Policies and Note 12 - Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Purchase Accounting (Exelon, Generation and PHI) Assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. Determining the fair value of assets acquired and liabilities assumed requires management's judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. If the transaction is determined to be an asset acquisition the purchase price is allocated to the assets acquired and the liabilities assumed and no goodwill or bargain purchase gain would be recorded. See Note 2 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. Unamortized Energy Contract Assets and Liabilities (Exelon, Generation and PHI) Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has acquired and the electricity contracts Exelon has acquired as part of the PHI merger. The initial amount recorded represents the fair value of the contracts at the time of acquisition. At Exelon and PHI, offsetting regulatory assets or liabilities were also recorded for those energy contract costs that are probable of recovery or refund through customer rates. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract assets and liabilities is recorded through purchased power and fuel expense or operating revenues, depending on the nature of the underlying contract. See Note 3 - Regulatory Matters, Note 2 - Mergers, Acquisitions and Dispositions and Note 12 - Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Impairment of Long-Lived Assets (All Registrants) All Registrants regularly monitor and evaluate the carrying value of long-lived assets and asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, an asset remaining idle for more than a short period of time, specific regulatory disallowance, advances in technology, plans to dispose of a long-lived asset significantly before the end of its useful life, and financial distress of a third party for assets contracted with them on a long-term basis, among others. The review of long-lived assets and asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units as well as the associated intangible assets or 77
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liabilities recorded on the balance sheet. The cash flows from the generating
units are generally evaluated at a regional portfolio level with cash flows
generated from the customer supply and risk management activities, including
cash flows from related intangible assets and liabilities on the balance sheet.
In certain cases, generating assets may be evaluated on an individual basis
where those assets are contracted on a long-term basis with a third party and
operations are independent of other generating assets (typically contracted
renewables). For such assets the financial viability of the third party,
including the impact of bankruptcy on the contract, may be a significant
assumption in the assessment.
On a quarterly basis, Generation assesses its long-lived assets or asset groups
for indicators of impairment. If indicators are present for a long-lived asset
or asset group, a comparison of the undiscounted expected future cash flows to
the carrying value is performed. When the undiscounted cash flow analysis
indicates the carrying value of a long-lived asset or asset group is not
recoverable, the amount of the impairment loss is determined by measuring the
excess of the carrying amount of the long-lived asset or asset group over its
fair value. The fair value of the long-lived asset or asset group is dependent
upon a market participant's view of the exit price of the assets. This includes
significant assumptions of the estimated future cash flows generated by the
assets and market discount rates. Events and circumstances often do not occur as
expected and there will usually be differences between prospective financial
information and actual results, and those differences may be material. The
determination of fair value is driven by both internal assumptions that include
significant unobservable inputs (Level 3) such as revenue and generation
forecasts, projected capital, and maintenance expenditures and discount rates,
as well as information from various public, financial and industry sources.
See Note 11 - Asset Impairments of the Combined Notes to Consolidated Financial
Statements for a discussion of asset impairment assessments.
Depreciable Lives of Property, Plant and Equipment (All Registrants)
The Registrants have significant investments in electric generation assets and
electric and natural gas transmission and distribution assets. These assets are
generally depreciated on a straight-line basis, using the group, composite or
unitary methods of depreciation. The group approach is typically for groups of
similar assets that have approximately the same useful lives and the composite
approach is used for heterogeneous assets that have different lives. Under both
methods, a reporting entity depreciates the assets over the average life of the
assets in the group. The estimation of asset useful lives requires management
judgment, supported by formal depreciation studies of historical asset
retirement experience. Depreciation studies are generally completed every five
years, or more frequently if required by a rate regulator or if an event,
regulatory action, or change in retirement patterns indicate an update is
necessary.
For the Utility Registrants, depreciation studies generally serve as the basis
for amounts allowed in customer rates for recovery of depreciation costs.
Generally, the Utility Registrants adjust their depreciation rates for financial
reporting purposes concurrent with adjustments to depreciation rates reflected
in customer rates, unless the depreciation rates reflected in customer rates do
not align with management's judgment as to an appropriate estimated useful life
or have not been updated on a timely basis. Depreciation expense and customer
rates for ComEd, BGE, Pepco, DPL and ACE includes an estimate of the future
costs of dismantling and removing plant from service upon retirement. See Note 3
- Regulatory Matters of the Combined Notes to the Consolidated Financial
Statements for information regarding regulatory liabilities and assets recorded
by ComEd, BGE, Pepco, DPL and ACE related to removal costs.
PECO's removal costs are capitalized to accumulated depreciation when incurred,
and recorded to depreciation expense over the life of the new asset constructed
consistent with PECO's regulatory recovery method. Estimates for such removal
costs are also evaluated in the periodic depreciation studies.
At Generation, along with depreciation study results, management considers
expected future energy market conditions and generation plant operating costs
and capital investment requirements in determining the estimated service lives
of its generating facilities. See Note 6 - Early Plant Retirements of the
Combined Notes to the Consolidated Financial Statements for additional
information.
Changes in estimated useful lives of electric generation assets and of electric
and natural gas transmission and distribution assets could have a significant
impact on the Registrants' future results of operations. See Note 1 -
Significant Accounting Policies of the Combined Notes to Consolidated Financial
Statements for information regarding depreciation and estimated service lives of
the property, plant and equipment of the Registrants.
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Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants) Exelon sponsors defined benefit pension plans and other postretirement employee benefit plans for substantially all current employees. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's expected level of contributions to the plans, the incidence of participant mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. Exelon amortizes actuarial gains or losses in excess of a corridor of 10% of the greater of the projected benefit obligation or the market-related value (MRV) of plan assets over the expected average remaining service period of plan participants. Pension and other postretirement benefit plan assets include equity securities, includingU.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity and hedge funds. Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon's target asset class allocations. Exelon calculates the amount of expected return on pension and other postretirement benefit plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For other postretirement benefit plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV. Discount Rate. AtDecember 31, 2019 and 2018, the discount rates were determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and other postretirement benefit obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and other postretirement benefit plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates. Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon's mortality assumption is supported by an actuarial experience study of Exelon's plan participants and beginning in 2019, utilizes theSociety of Actuaries' 2019 base table (Pri-2012) and MP-2019 improvement scale adjusted to a 0.75% long-term rate reached in 2035. 79
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Sensitivity to Changes in Key Assumptions. The following tables illustrate the
effects of changing certain of the actuarial assumptions discussed above, while
holding all other assumptions constant (dollars in millions):
Actual Assumption
Change in
Actuarial Assumption Pension OPEB Assumption Pension
OPEB Total
Change in 2019 cost:
Discount rate (a) 4.31% 4.30% 0.5% $ (47 ) $ (14 ) $ (61 )
4.31% 4.30% (0.5)% 47 13 60
EROA 7.00% 6.67% 0.5% (88 ) (11 ) (99 )
7.00% 6.67% (0.5)% 88 11 99
Change in benefit
obligation at December 31,
2019:
Discount rate (a) 3.34% 3.31% 0.5% (1,244 ) (247 ) (1,491 )
3.34% 3.31% (0.5)% 1,316 261 1,577
__________(a) In general, the discount rate will have a larger impact on the pension and
other postretirement benefit cost and obligation as the rate moves closer to
0%. Therefore, the discount rate sensitivities above cannot necessarily be
extrapolated for larger increases or decreases in the discount rate.
Additionally, Exelon utilizes a liability-driven investment strategy for its
pension asset portfolio. The sensitivities shown above do not reflect the
offsetting impact that changes in discount rates may have on pension asset
returns.
See Note 14 - Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and other postretirement benefit plans. Regulatory Accounting (Exelon and Utility Registrants) For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities' cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, Exelon and the Utility Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact would be recognized in the Consolidated Statements of Operations and Comprehensive Income and could be material. The following table illustrates the gains (losses) that could result from the elimination of regulatory assets and liabilities and charges against OCI (dollars in millions before taxes) related to deferred costs associated with Exelon's pension and other postretirement benefit plans that are recorded as regulatory assets in Exelon's Consolidated Balance Sheets: December 31, 2019 Exelon ComEd PECO BGE PHI Pepco DPL ACE Gain (loss)$ 887 $ 4,981 $ 6 $ 591 $ (696 ) $ (18 ) $ 337 $ (43 ) Charge against OCI(a)$ 3,864 $ - $ - $ - $ - $
- $ - $ -
___________
(a) Exelon's charge against OCI (before taxes) consists of up to
related to ComEd's, BGE's, PHI's, Pepco's, DPL's and ACE's respective
portions of the deferred costs associated with Exelon's pension and other
postretirement benefit plans. Exelon also has a net regulatory liability of
associated with Exelon's other postretirement benefit plans that would result
in an increase in OCI if reversed.
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See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities tables of Exelon and the Utility Registrants. For each regulatory jurisdiction in which they conduct business, Exelon and the Utility Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material. Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, andFERC transmission formula rate tariffs for the Utility Registrants. Accounting for Derivative Instruments (All Registrants) The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk and interest rate risk related to ongoing business operations. The Registrants' derivative activities are in accordance with Exelon's Risk Management Policy (RMP). See Note 15 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlyings and one or more notional quantities. Changes in management's assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope to new authoritative guidance. All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives entered into for economic hedging and for proprietary trading purposes are recorded at fair value through earnings. For economic hedges that are not designated for hedge accounting for the Utility Registrants, changes in the fair value each period are generally recorded with a corresponding offsetting regulatory asset or liability given likelihood of recovering the associated costs through customer rates. Normal Purchases and Normal Sales Exception. As part of Generation's energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated by Generation as NPNS transactions, which are thus not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed. Contracts that qualify for the NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of ComEd's energy procurement process, PECO's full requirement contracts under the PAPUC-approved DSP program, most of PECO's natural gas supply agreements, all of BGE's full requirement contracts and natural gas supply agreements that are derivatives and certain Pepco, DPL and ACE full requirement contracts qualify for and are accounted for under the NPNS. Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP. As a part of the authoritative guidance, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether or not to enter into derivative 81
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transactions, and in determining the initial accounting treatment for derivative
transactions. Under the authoritative guidance for fair value measurements, the
Registrants categorize these derivatives under a fair value hierarchy that
prioritizes the inputs to valuation techniques used to measure fair value.
Derivative contracts are traded in both exchange-based and non-exchange-based
markets. Exchange-based derivatives that are valued using unadjusted quoted
prices in active markets are generally categorized in Level 1 in the fair value
hierarchy.
Certain derivatives' pricing is verified using indicative price quotations
available through brokers or over-the-counter, on-line exchanges. The price
quotations reflect the average of the bid-ask mid-point from markets that the
Registrants believe provide the most liquid market for the commodity. The price
quotations are reviewed and corroborated to ensure the prices are observable and
representative of an orderly transaction between market participants. The
Registrant's derivatives are traded predominately at liquid trading points. The
remaining derivative contracts are valued using models that consider inputs such
as contract terms, including maturity, and market parameters, and assumptions of
the future prices of energy, interest rates, volatility, credit worthiness and
credit spread. For derivatives that trade in liquid markets, such as generic
forwards, swaps and options, the model inputs are generally observable. Such
instruments are categorized in Level 2.
For derivatives that trade in less liquid markets with limited pricing
information, the model inputs generally would include both observable and
unobservable inputs and are categorized in Level 3.
The Registrants consider nonperformance risk, including credit risk in the
valuation of derivative contracts, including both historical and current market
data in its assessment of nonperformance risk, including credit risk. The
impacts of nonperformance and credit risk to date have generally not been
material to the financial statements.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note
17 - Fair Value of Financial Assets and Liabilities and Note 15 - Derivative
Financial Instruments of the Combined Notes to Consolidated Financial Statements
for additional information regarding the Registrants' derivative instruments.
Taxation (All Registrants)
Significant management judgment is required in determining the Registrants'
provisions for income taxes, primarily due to the uncertainty related to tax
positions taken, as well as deferred tax assets and liabilities and valuation
allowances. The Registrants account for uncertain income tax positions using a
benefit recognition model with a two-step approach including a
more-likely-than-not recognition threshold and a measurement approach based on
the largest amount of tax benefit that is greater than 50% likely of being
realized upon ultimate settlement. Management evaluates each position based
solely on the technical merits and facts and circumstances of the position,
assuming the position will be examined by a taxing authority having full
knowledge of all relevant information. Significant judgment is required to
determine whether the recognition threshold has been met and, if so, the
appropriate amount of tax benefits to be recorded in the Registrants'
consolidated financial statements.
The Registrants evaluate quarterly the probability of realizing deferred tax
assets by reviewing a forecast of future taxable income and their intent and
ability to implement tax planning strategies, if necessary, to realize deferred
tax assets. The Registrants also assess negative evidence, such as the
expiration of historical operating loss or tax credit carryforwards, that could
indicate the Registrant's inability to realize its deferred tax assets. Based on
the combined assessment, the Registrants record valuation allowances for
deferred tax assets when it is more-likely-than-not such benefit will not be
realized in future periods.
Actual income taxes could vary from estimated amounts due to the future impacts
of various items, including future changes in income tax laws, the Registrants'
forecasted financial condition and results of operations, failure to
successfully implement tax planning strategies, as well as results of audits and
examinations of filed tax returns by taxing authorities. See Note 13 - Income
Taxes of the Combined Notes to Consolidated Financial Statements for additional
information.
Accounting for Loss Contingencies (All Registrants)
In the preparation of their financial statements, the Registrants make judgments
regarding the future outcome of contingent events and record liabilities for
loss contingencies that are probable and can be reasonably estimated based upon
available information. The amount recorded may differ from the actual expense
incurred when the
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uncertainty is resolved. Such difference could have a significant impact in the
Registrants' consolidated financial statements.
Environmental Costs. Environmental investigation and remediation liabilities are
based upon estimates with respect to the number of sites for which the
Registrants will be responsible, the scope and cost of work to be performed at
each site, the portion of costs that will be shared with other parties, the
timing of the remediation work and changes in technology, regulations and the
requirements of local governmental authorities. Annual studies and/or reviews
are conducted at ComEd, PECO, BGE and DPL to determine future remediation
requirements for MGP sites and estimates are adjusted accordingly. In addition,
periodic reviews are performed at each of the Registrants to assess the adequacy
of other environmental reserves. These matters, if resolved in a manner
different from the estimate, could have a significant impact in the Registrants'
consolidated financial statements. See Note 18 - Commitments and Contingencies
of the Combined Notes to Consolidated Financial Statements for additional
information.
Other, Including Personal Injury Claims. The Registrants are self-insured for
general liability, automotive liability, workers' compensation, and personal
injury claims to the extent that losses are within policy deductibles or exceed
the amount of insurance maintained. The Registrants have reserves for both open
claims asserted and an estimate of claims incurred but not reported (IBNR). The
IBNR reserve is estimated based on actuarial assumptions and analysis and is
updated annually. Future events, such as the number of new claims to be filed
each year, the average cost of disposing of claims, as well as the numerous
uncertainties surrounding litigation and possible state and national legislative
measures could cause the actual costs to be higher or lower than estimated.
Accordingly, these claims, if resolved in a manner different from the estimate,
could have a material impact in the Registrants' consolidated financial
statements.
Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment. The Registrants
earn revenues from various business activities including: the sale of power and
energy-related products, such as natural gas, capacity, and other commodities in
non-regulated markets (wholesale and retail); the sale and delivery of power and
natural gas in regulated markets; and the provision of other energy-related
non-regulated products and services.
The accounting treatment for revenue recognition is based on the nature of the
underlying transaction and applicable authoritative guidance. The Registrants
primarily apply the Revenue from Contracts with Customers, Derivative and
Alternative Revenue Program (ARP) guidance to recognize revenue as discussed in
more detail below.
Revenue from Contracts with Customers. The Registrants recognize revenues in the
period in which the performance obligations within contracts with customers are
satisfied, which generally occurs when power, natural gas, and other
energy-related commodities are physically delivered to the customer.
Transactions of the Registrants within the scope of Revenue from Contracts with
Customers generally include non-derivative agreements, contracts that are
designated as NPNS, sales to utility customers under regulated service tariffs,
and spot-market energy commodity sales, including settlements with independent
system operators.
The determination of Generation's and the Utility Registrants' retail power and
natural gas sales to individual customers is based on systematic readings of
customer meters, generally on a monthly basis. At the end of each month, amounts
of energy delivered to customers since the date of the last meter reading are
estimated, and corresponding unbilled revenue is recorded. The measurement of
unbilled revenue is affected by the following factors: daily customer usage
measured by generation or gas throughput volume, customer usage by class, losses
of energy during delivery to customers and applicable customer rates. Increases
or decreases in volumes delivered to the utilities' customers and favorable or
unfavorable rate mix due to changes in usage patterns in customer classes in the
period could be significant to the calculation of unbilled revenue. In addition,
revenues may fluctuate monthly as a result of customers electing to use an
alternate supplier, since unbilled commodity revenues are not recorded for these
customers. Changes in the timing of meter reading schedules and the number and
type of customers scheduled for each meter reading date also impact the
measurement of unbilled revenue; however, total operating revenues would remain
materially unchanged. See Note 1 - Significant Accounting Policies of the
Combined Notes to Consolidated Financial Statements for additional information.
Derivative Revenues. The Registrants record revenues and expenses using the
mark-to-market method of accounting for transactions that are accounted for as
derivatives. These derivative transactions primarily relate to commodity price
risk management activities. Mark-to-market revenues and expenses include:
inception gains or
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losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses. Alternative Revenue Program Accounting. Certain of the Utility Registrants' ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants' formula rate and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of "originating" ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the "originating" ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers. ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC andFERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval byFERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Allowance for Uncollectible Accounts (Utility Registrants) Utility Registrants estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar credit quality indicators that are comprised based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Utility Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU regulations. Results of Operations by Registrant The Registrants' 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. For the Utility Registrants, their Operating revenues reflect the full and current recovery of commodity procurement costs given the rider mechanisms approved by their respective state regulators. The commodity procurement costs, which are recorded in Purchased power and fuel expense, and the associated revenues can be volatile. Therefore, the Utility Registrants believe that RNF is a useful measure because it excludes the effect on Operating revenues caused by the volatility in these expenses. 84
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Generation
Results of Operations-Generation
Favorable (unfavorable) Favorable (unfavorable)
2019 2018 2019 vs. 2018 variance 2017 2018 vs. 2017 variance
Operating revenues $ 18,924 $ 20,437 $ (1,513 ) $ 18,500 $ 1,937
Purchased power and fuel expense 10,856 11,693 837 9,690 (2,003 )
Revenues net of purchased power
and fuel expense 8,068 8,744 (676 ) 8,810 (66 )
Other operating expenses
Operating and maintenance 4,718 5,464 746 6,299 835
Depreciation and amortization 1,535 1,797 262 1,457 (340 )
Taxes other than income taxes 519 556 37 555 (1 )
Total other operating expenses 6,772 7,817 1,045 8,311 494
Gain (loss) on sales of assets and
businesses 27 48 (21 ) 2 46
Bargain purchase gain - - - 233 (233 )
Gain on deconsolidation of business - - - 213 (213 )
Operating income 1,323 975 348 947 28
Other income and (deductions)
Interest expense (429 ) (432 ) 3 (440 ) 8
Other, net 1,023 (178 ) 1,201 948 (1,126 )
Total other income and (deductions) 594 (610 ) 1,204 508 (1,118 )
Income before income taxes 1,917 365 1,552 1,455 (1,090 )
Income taxes 516 (108 ) (624 ) (1,376 ) (1,268 )
Equity in losses of unconsolidated
affiliates (184 ) (30 ) (154 ) (33 ) 3
Net income 1,217 443 774 2,798 (2,355 )
Net income attributable to
noncontrolling interests 92 73 (19 ) 88 (15 )
Net income attributable to
membership interest $ 1,125 $ 370 $ 755 $ 2,710 $ (2,340 )
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 . Net
income attributable to membership interest increased by $755 million primarily
due to:
• Higher net unrealized and realized gains on NDT funds;
• Decreased accelerated depreciation and amortization due to the early
retirement of the Oyster Creek nuclear facility in September 2018 and
TMI in September 2019 and the absence of a charge associated with the
remeasurement of the Oyster Creek ARO;
• Decreased operating and maintenance expense at Generation which
includes the impacts of previous cost management programs and lowerpension and OPEB costs, and increased NEIL insurance distributions;
• A benefit associated with the remeasurement of the TMI ARO in the first
quarter of 2019 and the annual nuclear ARO update in the third quarter
of 2019;
• Decreased nuclear outage days;
• Lower mark-to-market losses;
• Research and development income tax credits.
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The increases were partially offset by; • Lower realized energy prices; and
• Lower capacity prices.
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. During the first quarter of 2019, due to a change in economics in ourNew England region, Generation changed the way that information is reviewed by the CODM. TheNew England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for theNew England region will be reviewed by the CODM as part of Other Power Regions. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments. The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues. Generation evaluates the operating performance of electric business activities using the measure of RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements. For the years endedDecember 31, 2019 compared to 2018, RNF by region were as follows: 2019 vs. 2018 2019 2018 Variance % Change Mid-Atlantic(a)$ 2,655 $ 3,073 $ (418 ) (13.6 )% Midwest(b) 2,962 3,135 (173 ) (5.5 )% New York 1,094 1,122 (28 ) (2.5 )% ERCOT 308 258 50 19.4 % Other Power Regions 620 729 (109 ) (15.0 )% Total electric revenues net of purchased power and fuel expense 7,639 8,317 (678 ) (8.2 )% Mark-to-market losses (215 ) (319 ) 104 (32.6 )% Other 644 746 (102 ) (13.7 )% Total revenue net of purchased power and fuel expense$ 8,068 $ 8,744 $ (676 ) (7.7 )% _________
(a) Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.
(b) Includes results of transactions with ComEd.
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Generation's supply sources by region are summarized below:
2019 vs. 2018
Supply Source (GWhs) 2019 2018 Variance % Change
Nuclear Generation(a)
Mid-Atlantic 58,347 64,099 (5,752 ) (9.0 )%
Midwest 94,890 94,283 607 0.6 %
New York 28,088 26,640 1,448 5.4 %
Total Nuclear Generation 181,325 185,022 (3,697 ) (2.0 )%
Fossil and Renewables
Mid-Atlantic 2,884 3,670 (786 ) (21.4 )%
Midwest 1,374 1,373 1 0.1 %
New York 5 3 2 66.7 %
ERCOT 13,572 11,180 2,392 21.4 %
Other Power Regions 11,476 13,256 (1,780 ) (13.4 )%
Total Fossil and Renewables 29,311 29,482 (171 ) (0.6 )%
Purchased Power
Mid-Atlantic 14,790 6,506 8,284 127.3 %
Midwest 1,424 996 428 43.0 %
ERCOT 4,821 6,550 (1,729 ) (26.4 )%
Other Power Regions 48,673 44,998 3,675 8.2 %
Total Purchased Power 69,708 59,050 10,658 18.0 %
Total Supply/Sales by Region
Mid-Atlantic(b) 76,021 74,275 1,746 2.4 %
Midwest(b) 97,688 96,652 1,036 1.1 %
New York 28,093 26,643 1,450 5.4 %
ERCOT 18,393 17,730 663 3.7 %
Other Power Regions 60,149 58,254 1,895 3.3 %Total Supply/Sales by Region 280,344 273,554 6,790 2.5 %
__________
(a) Includes the proportionate share of output where Generation has an undivided
ownership interest in jointly-owned generating plants and includes the total
output of plants that are fully consolidated (e.g. CENG).
(b) Includes affiliate sales to PECO, BGE, Pepco, DPL and ACE in the Mid-Atlantic
region and affiliate sales to ComEd in the Midwest region.
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Generation
For the years endedDecember 31, 2019 compared to 2018 changes in RNF by region were as follows: 2019 vs. 2018 (Decrease)/Increase Description Mid-Atlantic $ (418 ) • decreased revenue due to the permanent cease of generation operations at Oyster Creek in the third quarter of 2018 and Three Mile Island in the third quarter of 2019 • lower realized energy prices • decreased capacity prices, partially offset by • increased ZEC revenues due to the approval of the NJ ZEC program in the second quarter of 2019 Midwest (173 ) • the absence of the revenue recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017 • decreased capacity prices New York (28 ) • lower realized energy prices • decreased capacity prices, partially offset by • increased ZEC revenues due to higher ZEC prices and increased nuclear output • decreased nuclear outage days ERCOT 50 • higher realized energy prices Other Power Regions (109 ) • decreased capacity prices • lower realized energy prices Mark-to-market(a) 104 • losses on economic hedging activities of$215 million in 2019 compared to losses of$319 million in 2018 Other (102 ) • the absence of the gain on the settlement of a long-term gas supply agreement • congestion activity, partially offset by • decrease in accelerated nuclear fuel amortization associated with announced early plant retirements Total $ (676 ) _________ (a) See Note 15 - Derivative Financial Instruments for additional information on mark-to-market losses. 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. 2019 2018 Nuclear fleet capacity factor 95.7 % 94.6 % Refueling outage days 209 274 Non-refueling outage days 51 38 88
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Generation
The changes in Operating and maintenance expense, consisted of the following:
(Decrease) Increase
2019 vs. 2018
Labor, other benefits, contracting, materials(a) $ (174 )
Nuclear refueling outage costs, including the co-owned Salem plants (87 )
Corporate allocations (82 )
Insurance(b) (47 )
Merger and integration costs (4 )
Plant retirements and divestitures(c) (175 )
Change in environmental liabilities 7
ARO update(d) (70 )
Asset Impairments(e) (32 )
Pension and non-pension postretirement benefits expense (62 )
Allowance for uncollectible accounts (14 )
Accretion expense (77 )
Other(f) 71
Decrease in operating and maintenance expense $ (746 )
__________
(a) Primarily reflects decreased costs related to the permanent cease of
generation operations at Oyster Creek, lower labor costs resulting from
previous cost management programs, and lower pension and OPEB costs.
(b) Primarily reflects a supplemental NEIL insurance distribution received in the
fourth quarter of 2019.
(c) Primarily due to the benefit recorded in the first quarter of 2019 for the
remeasurement of the TMI ARO and the absence of a charge associated with the
remeasurement of the Oyster Creek ARO in the third quarter of 2018.
(d) Primarily reflects a benefit related to Generation's annual nuclear ARO
update for non-regulatory units.
(e) Primarily due to the impairment of certain wind projects recorded in the
second quarter of 2018.
(f) Primarily due to the increased revenue as a result of a research and
development tax refund.
Depreciation and amortization expense for the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 decreased primarily due to the permanent cessation of generation operations at Oyster Creek in the third quarter of 2018 and TMI in the fourth quarter of 2019. Gain (loss) on sales of assets and businesses for the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 decreased primarily due to Generation's sale of Oyster Creek. Other, net for the year endedDecember 31, 2019 compared to the same period in 2018 increased for the twelve months endedDecember 31, 2019 compared to the same period in 2018 due to activity associated with NDT funds as described in the table below. 2019 2018
Net unrealized gains (losses) on NDT funds(a)
253 180
Interest and dividend income on NDT funds(a) 110 122
Contractual elimination of income tax expense(b) 216 (38 )
Other 33 41
Total other, net $ 1,023 $ (178 )
_________(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.
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Generation
Effective income tax rates were 26.9% and (29.5)% for the years endedDecember 31, 2019 and 2018, respectively. The change in 2019 is primarily related to research and development claims, renewable tax credits and one-time adjustments. See Note 13 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Equity in losses of unconsolidated affiliates for the twelve months endedDecember 31, 2019 compared to the same period in 2018 decreased primarily due to the impairment of equity method investments in certain distributed energy companies. Net income attributable to noncontrolling interests for the twelve months endedDecember 31, 2019 compared to the same period in 2018 decreased primarily due to the offsetting noncontrolling interest impact of the impairment of equity method investments in certain distributed energy companies. 90
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ComEd
Results of Operations-ComEd
Favorable
Favorable (unfavorable)
(unfavorable) 2019 2018 vs. 2017
2019 2018 vs. 2018 variance 2017 variance
Operating revenues $ 5,747 $ 5,882 $ (135 ) $ 5,536 $ 346
Purchased power expense 1,941 2,155 214 1,641 (514 )
Revenues net of purchased power
expense 3,806 3,727 79 3,895 (168 )
Other operating expenses
Operating and maintenance 1,305 1,335 30 1,427 92
Depreciation and amortization 1,033 940 (93 ) 850 (90 )
Taxes other than income taxes 301 311 10 296 (15 )
Total other operating expenses 2,639 2,586 (53 ) 2,573 (13 )
Gain on sales of assets 4 5 (1 ) 1 4
Operating income 1,171 1,146 25 1,323 (177 )
Other income and (deductions)
Interest expense, net (359 ) (347 ) (12 ) (361 ) 14
Other, net 39 33 6 22 11
Total other income and
(deductions) (320 ) (314 ) (6 ) (339 ) 25
Income before income taxes 851 832 19 984 (152 )
Income taxes 163 168 5 417 249
Net income $ 688 $ 664 $ 24 $ 567 $ 97
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 . Net
income increased by $24 million primarily due to higher electric distribution,
transmission and energy efficiency formula rate earnings (reflecting the impacts
of higher rate base, partially offset by lower allowed electric distribution ROE
due to a decrease in treasury rates).
Revenues Net of Purchased Power Expense. There are certain drivers of Operating
revenues that are fully offset by their impact on Purchased power expense, such
as commodity, REC and ZEC procurement costs and participation in customer choice
programs. ComEd recovers electricity, REC and ZEC procurement costs from
customers without mark-up. Therefore, fluctuations in these costs have no impact
on RNF.
Customers have the choice to purchase electricity from a competitive electric
generation supplier. Customer choice programs do not impact the volume of
deliveries, but do impact Operating revenues related to supplied electricity.
The changes in RNF consisted of the following:
Increase (Decrease)
2019 vs. 2018
Electric distribution revenue $ 47
Transmission revenue 32
Energy efficiency revenue 47
Uncollectible accounts recovery, net (7 )
Other (40 )
Total increase $ 79
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ComEd
Revenue Decoupling. The demand for electricity is affected by weather and
customer usage. Operating revenues are not impacted by abnormal weather, usage
per customer or number of customers as a result of 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. During the year ended
December 31, 2019 , as compared to the same period in 2018, electric distribution
revenue increased primarily due to the impact of higher rate base and increased
depreciation expenses, offset by lower allowed ROE due to a decrease in treasury
rates. See Operating and Maintenance Expense below and Note 3 - 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. During the year ended December 31, 2019 , as compared to
the same period in 2018, transmission revenue increased primarily due to the
impact of increased peak load, higher rate base, and higher fully recoverable
costs. See Operating and Maintenance Expense below and Note 3 - 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 for the year ended
December 31, 2019 , as compared to the same period in 2018, primarily due to the
impact of higher rate base and increased regulatory asset amortization. See
Depreciation and amortization expense discussions below and Note 3 - Regulatory
Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
Uncollectible Accounts Recovery, Net represents recoveries under the
uncollectible accounts tariff. See Operating and maintenance expense discussion
below for additional information on this tariff.
Other revenue includes rental revenue, revenue related to late payment charges,
mutual assistance revenues and recoveries of environmental costs associated with
MGP sites. The decrease in Other revenue for the year ended December 31, 2019 ,
as compared to the same period in 2018, primarily reflects absence of mutual
assistance revenues associated with hurricane and winter storm restoration
efforts that occurred in Q1 2018. An equal and offsetting amount was included in
Operating and maintenance expense.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial
Statements for the presentation of ComEd's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
(Decrease) Increase
2019 vs. 2018
Baseline
Pension and non-pension postretirement benefits expense(a) $ (36 )
Labor, other benefits, contracting and materials(b) (27 )
Uncollectible accounts expense(c) (7 )
Storm costs 31
Other 9
Total decrease $ (30 )
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ComEd
__________(a) Primarily reflects an increase in discount rates and the favorable impacts of
the merger of two of Exelon's pension plans
effective inJanuary 2019 , partially offset by lower than expected asset returns in 2018. (b) Primarily reflects absence of mutual assistance expenses and decreased
contracting costs. An equal and offsetting increase has been recognized in
Operating revenues for the period presented.
(c) ComEd is allowed to recover from or refund to customers the difference
between its annual uncollectible accounts expense and the amounts collected
in rates annually through a rider mechanism. ComEd recorded a net decrease in
uncollectible accounts for the year ended
the same period in 2018, primarily due to the timing of regulatory cost
recovery. An equal and offsetting amount has been recognized in Operating
revenues for the periods presented.
The changes in Depreciation and amortization expense consisted of the following:
Increase
2019 vs. 2018
Depreciation expense(a) $ 58
Regulatory asset amortization(b) 35
Total increase $ 93
__________
(a) Reflects ongoing capital expenditures and higher depreciation rates effective
(b) Includes amortization of ComEd's energy efficiency formula rate regulatory
asset.
Effective income tax rates for the years ended December 31, 2019 and 2018, were
19.2% and 20.2% , respectively. See Note 13 - Income Taxes of the Combined Notes
to Consolidated Financial Statements for additional information regarding the
components of the effective income tax rates.
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PECO
Results of Operations-PECO
Favorable
Favorable (unfavorable)
(unfavorable) 2019 2018 vs. 2017
2019 2018 vs. 2018 variance 2017 variance
Operating revenues $ 3,100 $ 3,038 $ 62 $ 2,870 $ 168
Purchased power and fuel expense 1,029 1,090 61 969 (121 )
Revenues net of purchased power
and fuel expense 2,071 1,948 123 1,901 47
Other operating expenses
Operating and maintenance 861 898 37 806 (92 )
Depreciation and amortization 333 301 (32 ) 286 (15 )
Taxes other than income taxes 165 163 (2 ) 154 (9 )
Total other operating expenses 1,359 1,362 3 1,246 (116 )
Gain on sales of assets 1 1 - - 1
Operating income 713 587 126 655 (68 )
Other income and (deductions)
Interest expense, net (136 ) (129 ) (7 ) (126 ) (3 )
Other, net 16 8 8 9 (1 )
Total other income and
(deductions) (120 ) (121 ) 1 (117 ) (4 )
Income before income taxes 593 466 127 538 (72 )
Income taxes 65 6 (59 ) 104 98
Net income $ 528 $ 460 $ 68 $ 434 $ 26
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 . Net
income increased by $68 million primarily due to higher electric distribution
rates that became effective January 2019 , higher natural gas distribution rates
and lower storm costs, partially offset by unfavorable weather conditions and
volume.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers of
Operating revenues that are fully offset by their impact on Purchased power and
fuel expenses such as commodity and REC procurement costs and participation in
customer choice programs. PECO's recovers electricity, natural gas and REC
procurement costs from customers without mark-up. Therefore, fluctuations in
these costs have no impact on RNF.
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 or RNF, but impact Operating
revenues related to supplied electricity and natural gas.
The changes in RNF consisted of the following:
2019 vs. 2018
(Decrease) Increase
Electric Gas Total
Weather $ (11 ) $ (8 ) $ (19 )
Volume (22 ) 6 (16 )
Pricing 112 10 122
Regulatory required programs 42 9 51
Transmission Revenue (13 ) - (13 )
Other (2 ) - (2 )
Total increase $ 106 $ 17 $ 123
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PECO
Weather. The demand for electricity and natural gas is affected by weather
conditions. With respect to the electric business, very warm weather in summer
months and, with respect to the electric and natural gas businesses, very cold
weather in winter months are referred to as "favorable weather conditions"
because these weather conditions result in increased deliveries of electricity
and natural gas. Conversely, mild weather reduces demand. For the year ended
December 31, 2019 compared to the same period in 2018 RNF was 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 years ended December 31, 2019
and December 31, 2018 compared to the same periods in 2018 and 2017,
respectively, and normal weather consisted of the following:
For the Years Ended December 31, % Change
Heating and Cooling
Degree-Days 2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days 4,307 4,539 4,458 (5.1 )% (3.4 )%
Cooling Degree-Days 1,610 1,584 1,415 1.6 % 13.8 %
Volume. Electric volume, exclusive of the effects of weather, for the year ended
December 31, 2019 compared to the same period in 2018, decreased due to lower
customer usages for residential, commercial and industrial electric classes,
partially offset by the impact of customer growth. Natural gas volume for the
year ended December 31, 2019 compared to the same period in 2018, increased due
to customer and economic growth.
% Change Weather -
2019 vs. Normal %
Electric Retail Deliveries to Customers (in GWhs) 2019 2018 2018 Change(b)
Retail Deliveries (a)
Residential 13,650 14,005 (2.5 )% (1.4 )%
Small commercial & industrial 7,983 8,177 (2.4 )% (1.2 )%
Large commercial & industrial 14,958 15,516 (3.6 )% (3.4 )%
Public authorities & electric railroads 725 761 (4.7 )% (5.0 )%
Total electric retail deliveries 37,316 38,459 (3.0 )% (2.3 )%
__________
(a) Reflects delivery volumes and revenue from customers purchasing electricity
directly from PECO and customers purchasing electricity from a competitive
electric generation supplier as all customers are assessed distribution
charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on
the historical 30-year average.
As of December 31,
Number of Electric Customers 2019 2018
Residential 1,494,462 1,480,925
Small commercial & industrial 154,000 152,797
Large commercial & industrial 3,104 3,118
Public authorities & electric railroads 10,039 9,565
Total 1,661,605 1,646,405
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PECO
Weather -
% Change Normal %
Natural Gas Deliveries to customers (in mmcf) 2019 2018 2019 vs. 2018 Change(b)
Retail Deliveries (a)
Residential 40,196 43,450 (7.5 )% 0.9 %
Small commercial & industrial 23,828 21,997 8.3 % 1.4 %
Large commercial & industrial 50 65 (23.1 )% 7.4 %
Transportation 25,822 26,595 (2.9 )% (1.3 )%
Total natural gas deliveries 89,896 92,107 (2.4 )% 0.4 %
__________
(a) Reflects delivery volumes and revenue from customers purchasing electricity
directly from PECO and customers purchasing electricity from a competitive
electric generation supplier as all customers are assessed distribution
charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on
the historical 30-year average.
As of December 31,
Number of Gas Customers 2019 2018
Residential 487,337 482,255
Small commercial & industrial 44,374 44,170
Large commercial & industrial 2 1
Transportation 730 754
Total 532,443 527,180
Pricing for the year ended December 31, 2019 compared to the same period in 2018
increased primarily due to an increase in electric distribution rates charged to
customers. The increase in electric distribution rates was effective January 1,
2019 in accordance with the 2018 PAPUC approved electric distribution rate case
settlement. Additionally, the increase represents revenue from higher natural
gas distribution rates. See Note 3 - 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, 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 Operating and
maintenance expense, Depreciation and amortization expense and Income taxes.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies
from year to year based upon fluctuations in the underlying costs and capital
investments being recovered. Transmission revenue for the year ended
December 31, 2019 compared to the same period in 2018 decreased primarily due to
lower operating and maintenance expenses and the terms of the settlement
agreement approved by FERC in December 2019 . See Note 3 - Regulatory Matters of
the Combined Notes to Consolidated Financial Statements for additional
information.
Other revenue includes rental revenue, revenue related to late payment charges
and mutual assistance revenues.
See Note 5-Segment Information of the Combined Notes to Consolidated Financial
Statements for the presentation of PECO's revenue disaggregation.
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PECO
The changes in Operating and maintenance expense consisted of the following:
(Decrease) Increase
2019 vs. 2018
Baseline
Storm-related costs (a) $ (30 )
Pension and non-pension postretirement benefits expense (5 )
Uncollectible accounts expense (2 )
BSC costs 2
Labor, other benefits, contracting and materials 1
Other (7 )
(41 )
Regulatory required programs
Energy efficiency 4
Decrease in operating and maintenance expense $ (37 )
__________
(a) Reflects decreased storm costs due to the
The changes in Depreciation and amortization expense consisted of the following:
Increase
2019 vs. 2018
Depreciation expense (a) $ 28
Regulatory asset amortization 4
Increase in depreciation and amortization expense $ 32
__________
(a) Depreciation expense increased due to ongoing capital expenditures. Effective income tax rates were 11.0% and 1.3% for the years endedDecember 31, 2019 and 2018, respectively. See Note 13 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information of the change in effective income tax rates. 97
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BGE
Results of Operations-BGE
Favorable
(unfavorable) Favorable
2019 vs. 2018 (unfavorable) 2018
2019 2018 variance 2017 vs. 2017 variance
Operating revenues $ 3,106 $ 3,169 $ (63 ) $ 3,176 $ (7 )
Purchased power and fuel
expense 1,052 1,182 130 1,133 (49 )
Revenues net of
purchased power and fuel
expense 2,054 1,987 67 2,043 (56 )
Other operating expenses
Operating and
maintenance 760 777 17 716 (61 )
Depreciation and
amortization 502 483 (19 ) 473 (10 )
Taxes other than income
taxes 260 254 (6 ) 240 (14 )
Total other operating
expenses 1,522 1,514 (8 ) 1,429 (85 )
Gain on sales of assets - 1 (1 ) - 1
Operating income 532 474 58 614 (140 )
Other income and
(deductions)
Interest expense, net (121 ) (106 ) (15 ) (105 ) (1 )
Other, net 28 19 9 16 3
Total other income and
(deductions) (93 ) (87 ) (6 ) (89 ) 2
Income before income
taxes 439 387 52 525 (138 )
Income taxes 79 74 (5 ) 218 144
Net income 360 313 47 307 6
Net income attributable
to common shareholder $ 360 $ 313 $ 47 $ 307 $ 6
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 . Net
income attributable to common shareholder increased by $47 million primarily due
to higher natural gas distribution rates that became effective January 2019 and
December 2019 , higher electric distribution rates that became effective December
2019 , and lower storm costs, partially offset by an increase in various
expenses, including interest.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to
Operating revenues that are fully offset by their impact on Purchased power and
fuel expense, such as commodity procurement costs and participation in customer
choice programs. BGE recovers electricity, natural gas and other procurement
costs from customers without mark-up. Therefore, fluctuations in these costs
have no impact on RNF.
Customers have the choice to purchase electricity and natural gas from electric
generation and natural gas competitive suppliers. Customer choice programs do
not impact the volume of deliveries or RNF but impact Operating revenues related
to supplied electricity and natural gas.
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BGE
The changes in RNF consisted of the following:
2019 vs. 2018
Increase (Decrease)
Electric Gas Total
Distribution revenue $ 11 $ 68 $ 79
Regulatory required programs (6 ) (4 ) (10 )
Transmission revenue 10 - 10
Other, net (7 ) (5 ) (12 )
Total increase $ 8 $ 59 $ 67
Revenue Decoupling. The demand for electricity and natural gas is affected by
weather and customer usage. However, Operating revenues are not impacted by
abnormal weather or usage per customer as a result of a bill stabilization
adjustment (BSA) that provides for a fixed distribution charge per customer by
customer class. While Operating revenues are not impacted by abnormal weather or
usage per customer, they are impacted by changes in the number of customers.
As of December 31,
Number of Electric Customers 2019 2018
Residential 1,177,333 1,168,372
Small commercial & industrial 114,504 113,915
Large commercial & industrial 12,322 12,253
Public authorities & electric railroads 268 262
Total 1,304,427 1,294,802
As of December 31,
Number of Gas Customers 2019 2018
Residential 639,426 633,757Small commercial & industrial 38,345 38,332 Large commercial & industrial 6,037 5,954 Total
683,808 678,043
Distribution Revenues increased during the year ended December 31, 2019 ,
compared to the same period in 2018, primarily due to the impact of higher
natural gas distribution rates that became effective in both January 2019 and
December 2019 and higher electric distribution rates that became effective in
December 2019 . See Note 3 - 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 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 Operating and maintenance expense,
Depreciation and amortization expense and Taxes other than income taxes.
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 increased during the year ended
December 31, 2019 compared to the same period in 2018, primarily due to
increases in capital investment and operating and maintenance expense
recoveries. See Operating and maintenance expense below and Note 3 - Regulatory
Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
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BGE
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation. The changes in Operating and maintenance expense consisted of the following:
(Decrease) Increase
2019 vs. 2018
Baseline
Storm-related costs(a) $ (24 )
Uncollectible accounts expense (2 )
BSC costs (1 )
Labor, other benefits, contracting and materials 8
Pension and non-pension postretirement benefits expense 1
Other 2
(16 )
Regulatory Required Programs (1 )
Total (decrease) increase $ (17 )
__________
(a) Reflects decreased storm restoration costs due to the
storms.
The changes in Depreciation and amortization expense consisted of the following:
Increase (Decrease)
2019 vs. 2018
Depreciation expense(a) $ 24
Regulatory asset amortization 4
Regulatory required programs (9 )
Increase in depreciation and amortization expense $ 19
__________
(a) Depreciation expense increased due to ongoing capital expenditures.
Interest expense, net increased during the year endedDecember 31, 2019 compared to the same period in 2018, primarily due to the issuances of debt inSeptember 2018 andSeptember 2019 . Other, net increased during the year endedDecember 31, 2019 compared to the same period in 2018, primarily due to higher AFUDC equity. Effective income tax rates were 18% and 19.1% for the years endedDecember 31, 2019 and 2018, respectively. See Note 13 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 100
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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. See the results of operations for Pepco, DPL, and ACE for additional
information.
Favorable Favorable
(unfavorable) 2019 (unfavorable) 2018
vs. 2018 variance vs. 2017 variance
2019 2018(a) 2017(a)
PHI $ 477 $ 393 $ 84 $ 355 $ 38
Pepco 243 205 38 198 7
DPL 147 120 27 121 (1 )
ACE 99 75 24 77 (2 )
Other(b) (12 ) (7 ) (5 ) (41 ) 34
_________(a) PHI's and Pepco's amounts have been revised to reflect the correction of an
error related to Pepco's decoupling mechanism. See Note 1 - Significant
Accounting Policies of the Combined Notes to Consolidated Financial
Statements for additional information.
(b) Primarily includes eliminating and consolidating adjustments, PHI's corporate
operations, shared service entities and other financing activities.
Year EndedDecember 31, 2019 Compared to Year EndedDecember 31, 2018 . Net income increased by$84 million primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, lower contracting costs, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, lower uncollectible accounts expense, and lower write-offs of construction work in progress, partially offset by an increase in environmental liabilities and various expenses. 101
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Pepco
Results of Operations-Pepco
Favorable Favorable
(unfavorable) 2019 (unfavorable) 2018
2019 2018(a) vs. 2018 variance 2017(a) vs. 2017 variance
Operating revenues $ 2,260 $ 2,232 $ 28 $ 2,151 $ 81
Purchased power expense 665 654 (11 ) 614 (40 )
Revenues net of purchased power
expense 1,595 1,578 17 1,537 41
Other operating expenses
Operating and maintenance 482 501 19 454 (47 )
Depreciation and amortization 374 385 11 321 (64 )
Taxes other than income taxes 378 379 1 371 (8 )
Total other operating expenses 1,234 1,265 31 1,146 (119 )
Gain on sales of assets - - - 1 (1 )
Operating income 361 313 48 392 (79 )
Other income and (deductions)
Interest expense, net (133 ) (128 ) (5 ) (121 ) (7 )
Other, net 31 31 - 32 (1 )
Total other income and
(deductions) (102 ) (97 ) (5 ) (89 ) (8 )
Income before income taxes 259 216 43 303 (87 )
Income taxes 16 11 (5 ) 105 94
Net income $ 243 $ 205 $ 38 $ 198 $ 7
__________(a) Amounts have been revised to reflect the correction of an error related to
Pepco's decoupling mechanism. See Note 1 - Significant Accounting Policies of
the Combined Notes to Consolidated Financial Statements for additional
information.
Year EndedDecember 31, 2019 Compared to Year EndedDecember 31, 2018 . Net income increased by$38 million primarily due to higher electric distribution rates inMaryland that became effectiveAugust 2019 andJune 2018 (not reflecting the impact of TCJA), higher electric distribution rates in theDistrict of Columbia that became effectiveAugust 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, and lower contracting costs, partially offset by an increase in environmental liabilities. Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. Therefore, fluctuations in these costs have minimal impact on RNF. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity. 102
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Pepco
The changes in RNF consisted of the following:
Increase (Decrease)
2019 vs. 2018
Volume $ 12
Distribution revenue 20
Regulatory required programs (35 )
Transmission revenues 18
Other 2
Total increase $ 17
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.
Volume, exclusive of the effects of weather, increased for the year ended
December 31, 2019 compared to the same period in 2018 primarily due to the
impact of residential customer growth.
As of December 31,
Number of Electric Customers 2019 2018
Residential 817,770 807,442
Small commercial & industrial 54,265 54,306
Large commercial & industrial 22,271 22,022
Public authorities & electric railroads 160 150
Total 894,466 883,920
Distribution Revenues increased for the year ended December 31, 2019 compared to
the same period in 2018 primarily due to higher electric distribution rates in
Maryland that became effective in August 2019 and June 2018 (not reflecting the
impact of TCJA), higher electric distribution rates (not reflecting the impact
of TCJA) in the District of Columbia that became effective in August 2018 ,
partially offset by the accelerated amortization of certain deferred income tax
regulatory liabilities established upon the enactment of TCJA as the result of
regulatory settlements. See Note 3 - 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, DC PLUG and SOS 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 Operating and maintenance expense,
Depreciation and amortization expense, and Taxes other than income taxes.
Revenues from regulatory programs decreased for the year ended December 31,
2019 compared to the same period in 2018 due to lower surcharge rates effective
January 2019 for energy efficiency programs that were implemented to reflect the
impacts of the enactment of TCJA.
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 revenue increased for the year ended
December 31, 2019 compared to the same period in 2018 due to rate increases and
an increase in the highest daily peak load.
Other revenue includes revenue related to late payment charges, mutual
assistance revenues, off-system sales and service application fees.
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See Note 5 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation. The changes in Operating and maintenance expense consisted of the following:
(Decrease) Increase
2019 vs. 2018
Baseline
BSC and PHISCO costs $ (16 )
Labor, other benefits, contracting and materials (11 )
Uncollectible accounts expense (3 )
Pension and Non-Pension Postretirement Benefits 6
Other 8
(16 )
Regulatory required programs (3 )
Total decrease $ (19 )
Increase (Decrease)
2019 vs. 2018
Depreciation expense(a) $ 21
Regulatory asset amortization 4
Regulatory required programs (36 )
Total decrease $ (11 )
__________
(a) Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Interest expense, net for the year endedDecember 31, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt. Effective income tax rates for the years endedDecember 31, 2019 and 2018 were 6.2% and 5.1%, respectively. See Note 13 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. 104
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DPL
Results of Operations-DPL
Favorable
(unfavorable) Favorable
2019 vs. 2018 (unfavorable) 2018
2019 2018 variance 2017 vs. 2017 variance
Operating revenues $ 1,306 $ 1,332 $ (26 ) $ 1,300 $ 32
Purchased power and fuel expense 526 561 35 532 (29 )
Revenues net of purchased power
and fuel expense 780 771 9 768 3
Other operating expenses
Operating and maintenance 323 344 21 315 (29 )
Depreciation and amortization 184 182 (2 ) 167 (15 )
Taxes other than income taxes 56 56 - 57 1
Total other operating expenses 563 582 19 539 (43 )
Gain on sales of assets - 1 (1 ) - 1
Operating income 217 190 27 229 (39 )
Other income and (deductions)
Interest expense, net (61 ) (58 ) (3 ) (51 ) (7 )
Other, net 13 10 3 14 (4 )
Total other income and
(deductions) (48 ) (48 ) - (37 ) (11 )
Income before income taxes 169 142 27 192 (50 )
Income taxes 22 22 - 71 49
Net income $ 147 $ 120 $ 27 $ 121 $ (1 )
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 . Net
income increased by $27 million primarily due to higher transmission revenues
due to an increase in the transmission rates and the highest daily peak load,
higher electric distribution rates in Maryland and Delaware that became
effective throughout 2018 (not reflecting the impact of TCJA), higher natural
gas distribution rates in Delaware that became effective throughout 2018 (not
reflecting the impact of TCJA), and lower write-offs of construction work in
progress.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to
Operating revenues that are fully offset by their impact on Purchased power and
fuel expense, such as commodity and REC procurement costs and participation in
customer choice programs. DPL recovers electricity and REC procurement costs
from customers with a slight mark-up and natural gas costs from customers
without mark-up. Therefore, fluctuations in these costs have minimal impact on
RNF.
Customers have the choice to purchase electricity from competitive electric
generation suppliers. Customer choice programs do not impact the volume of
deliveries or RNF, but impact Operating revenues related to supplied
electricity.
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DPL
The changes in RNF consisted of the following:
2019 vs. 2018
Increase (Decrease)
Electric Gas Total
Weather $ (3 ) $ (4 ) $ (7 )
Volume 1 2 3
Distribution revenue 2 1 3
Regulatory required programs (7 ) 2 (5 )
Transmission revenues 19 - 19
Other (4 ) - (4 )
Total increase $ 8 $ 1 $ 9
Revenue Decoupling. The demand for electricity is affected by weather and
customer usage. However, Operating revenues from electric distribution customers
in Maryland are not affected by unseasonably warmer or colder weather because 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.
Weather. The demand for electricity and natural gas in Delaware is affected by
weather conditions. With respect to the electric business, very warm weather in
summer months and, with respect to the electric and natural gas businesses, very
cold weather in winter months are referred to as "favorable weather conditions"
because these weather conditions result in increased deliveries of electricity
and natural gas. Conversely, mild weather reduces demand. During the year ended
December 31, 2019 compared to the same period in 2018, RNF related to weather
decreased primarily due to 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 year ended
December 31, 2019 compared to same period in 2018 and normal weather consisted
of the following:
For the Years Ended
Delaware Electric Service Territory December 31, % Change
Heating and Cooling Degree-Days 2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days 4,475 4,713 4,656 (5.0 )% (3.9 )%
Cooling Degree-Days 1,476 1,456 1,224 1.4 % 20.6 %
Delaware Natural Gas Service For the Years Ended
Territory December 31, % Change
Heating Degree-Days 2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days 4,475 4,713 4,698 (5.0 )% (4.7 )%
Volume, exclusive of the effects of weather, remained relatively consistent for
the year ended
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DPL
Weather -
% Change Normal %
Electric Retail Deliveries to Delaware Customers 2019 vs. Change
(in GWhs) 2019 2018 2018 (b)
Retail Deliveries
Residential 3,149 3,204 (1.7 )% (0.2 )%
Small commercial & industrial 1,320 1,344 (1.8 )% (1.4 )%
Large commercial & industrial 3,424 3,636 (5.8 )% (5.7 )%
Public authorities & electric railroads 34 33 3.0 % 0.9 %
Total electric retail deliveries(a) 7,927 8,217 (3.5 )% (2.9 )%
As of December 31,
Number of Total Electric Customers (Maryland and Delaware) 2019 2018
Residential 468,162
463,670
Small commercial & industrial 61,721
61,381
Large commercial & industrial 1,411
1,406
Public authorities & electric railroads 613 621 Total 531,907 527,078 __________
(a) Reflects delivery volumes and revenues from customers purchasing electricity
directly from DPL and customers purchasing electricity from a competitive
electric generation supplier as all customers are assessed distribution
charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on
the historical 20-year average.
% Change Weather -
Natural Gas Retail Deliveries to Delaware 2019 vs. Normal %
Customers (in mmcf) 2019 2018 2018 Change(b)
Retail Deliveries
Residential 8,613 8,633 (0.2 )% 4.2 %
Small commercial & industrial 4,287 4,134 3.7 % 7.8 %
Large commercial & industrial 1,811 1,952 (7.2 )% (7.1 )%
Transportation 6,733 6,831 (1.4 )% (0.2 )%
Total natural gas deliveries(a) 21,444 21,550 (0.5 )% 2.5 %
As of December 31 ,
Number of Delaware Gas Customers 2019 2018 Residential
125,873 124,183
Small commercial & industrial 9,999 9,986 Large commercial & industrial
17 18
Transportation 159 156
Total 136,048 134,343
_________(a) Reflects delivery volumes and revenues from customers purchasing natural gas
directly from DPL and customers purchasing natural gas from a competitive
natural gas supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on
the historical 30-year average.
Distribution Revenue increased for the year endedDecember 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates (not reflecting the impact of TCJA) inMaryland andDelaware that became effective throughout 2018 and higher natural gas distribution rates (not reflecting the impact of TCJA) inDelaware that became effective throughout 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 107
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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 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
Operating and maintenance expense, Depreciation and amortization expense and
Taxes other than income taxes.
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 years. Generally,
increases/decreases in the highest daily peak load will result in higher/lower
transmission revenue. Transmission revenue increased for the year ended
December 31, 2019 compared to the same period in 2018 due to rate increases and
an increase in the highest daily peak load.
Other revenue includes revenue related to late payment charges, mutual
assistance revenues, off-system sales and service application fees.
See Note 5 - Segment Information for the Combined Notes to Consolidated
Financial Statements for the presentation of DPL's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
(Decrease) Increase
2019 vs. 2018
Baseline
BSC and PHISCO costs $ (10 )
Write-off of construction work in progress (7 )
Uncollectible accounts expense (2 )
Pension and non-pension postretirement benefits expense 4
Labor, other benefits, contracting and materials 2
Storm-related costs (1 )
Other (6 )
(20 )
Regulatory required programs (1 )
Total decrease $ (21 )
The changes in Depreciation and amortization expense consisted of the following:
Increase (Decrease)
2019 vs. 2018
Depreciation expense(a) $ 14
Regulatory asset amortization (1 )
Regulatory required programs (11 )
Total increase $ 2
_________
(a) Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Interest expense, net for the year ended
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DPL
Effective income tax rates for the years ended December 31, 2019 and 2018 were
13.0% and 15.5%, respectively. See Note 13 - Income Taxes of the Combined Notes
to Consolidated Financial Statements for additional information regarding the
components of the change in effective income tax rates
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ACE
Results of Operations-ACE
Favorable Favorable
(unfavorable) 2019 (unfavorable) 2018
2019 2018 vs. 2018 variance 2017 vs. 2017 variance
Operating revenues $ 1,240 $ 1,236 $ 4 $ 1,186 $ 50
Purchased power expense 608 616 8 570 (46 )
Revenues net of purchased power
expense 632 620 12 616 4
Other operating expenses
Operating and maintenance 320 330 10 307 (23 )
Depreciation and amortization 157 136 (21 ) 146 10
Taxes other than income taxes 4 5 1 6 1
Total other operating expenses 481 471 (10 ) 459 (12 )
Gain on sales of assets - - - - -
Operating income 151 149 2 157 (8 )
Other income and (deductions)
Interest expense, net (58 ) (64 ) 6 (61 ) (3 )
Other, net 6 2 4 7 (5 )
Total other income and
(deductions) (52 ) (62 ) 10 (54 ) (8 )
Income (loss) before income
taxes 99 87 12 103 (16 )
Income taxes - 12 12 26 14
Net income $ 99 $ 75 $ 24 $ 77 $ (2 )
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 . Net
income increased $24 million primarily due to higher electric distribution rates
that became effective April 2019 and higher transmission revenues due to an
increase in the transmission rates and the highest daily peak load, partially
offset by lower average residential usage.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating
revenues that are fully offset by their impact on Purchased power expense, such
as commodity and REC procurement costs and participation in customer choice
programs. ACE recovers electricity and REC procurement costs from customers
without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from competitive electric
generation suppliers. Customer choice programs of supplier do not impact the
volume of deliveries or RNF, but impact revenues related to supplied
electricity.
The changes in RNF, consisted of the following:
(Decrease) Increase
2019 vs. 2018
Weather $ (6 )
Volume (11 )
Distribution revenue 36
Regulatory required programs (23 )
Transmission revenues 20
Other (4 )
Total increase $ 12
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ACE
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. During the year ended December 31, 2019
compared to the same period in 2018, RNF related to weather was lower due to the
impact of unfavorable weather conditions in ACE's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand
for energy needed to heat or cool a home or business. Normal weather is
determined based on historical average heating and cooling degree days for a
20-year period in ACE's service territory. The changes in heating and cooling
degree days in ACE's service territory for the year ended December 31, 2019
compared to same period in 2018, and normal weather consisted of the following:
For the Years Ended
December 31, % Change
Heating and Cooling Degree-Days 2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days 4,467 4,523 4,676 (1.2 )% (4.5 )%
Cooling Degree-Days 1,374 1,535 1,158 (10.5 )% 18.7 %
Volume, exclusive of the effects of weather, decreased for the year ended
% Change Weather -
2019 vs. Normal %
Electric Retail Deliveries to Customers (in GWhs) 2019 2018 2018 Change(b)
Retail Deliveries
Residential 3,966 4,185 (5.2 )% (3.5 )%
Small commercial & industrial 1,346 1,361 (1.1 )% 0.1 %
Large commercial & industrial 3,429 3,565 (3.8 )% (3.4 )%
Public authorities & electric railroads 47 49 (4.1 )% (2.9 )%
Total retail deliveries(a) 8,788 9,160 (4.1 )% (2.9 )%
As of December 31,
Number of Electric Customers 2019 2018
Residential 494,596 490,975
Small commercial & industrial 61,497 61,386
Large commercial & industrial 3,392 3,515
Public authorities & electric railroads 679 656
Total 560,164 556,532
__________
(a) Reflects delivery volumes and revenues from customers purchasing electricity
directly from ACE and customers purchasing electricity from a competitive
electric generation supplier as all customers are assessed distribution
charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on
the historical 20-year average.
Distribution Revenue increased for the year endedDecember 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution base rates that became effective inApril 2019 , partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 - 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 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 Operating and maintenance expense, Depreciation and 111
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ACE
amortization expense and Taxes other than income taxes. Revenues from regulatory
programs decreased for the year ended December 31, 2019 compared to the same
period in 2018 due to rate decreases effective October 2018 for the ACE
Transition Bonds.
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 revenue increased for the year ended
December 31, 2019 compared to the same period in 2018 primarily due to rate
increases and an increase in the highest daily peak load.
Other revenue includes revenue related to late payment charges, mutual
assistance revenues, off-system sales and service application fees.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial
Statements for the presentation of ACE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
(Decrease) Increase
2019 vs. 2018
Baseline
BSC and PHISCO costs $ (8 )
Uncollectible accounts expense(a) (6 )
Labor, other benefits, contracting and materials (5 )
Storm-related costs 2
Pension and non-pension postretirement benefits expense 1
Other 6
Total decrease $ (10 )
__________(a) ACE is allowed to recover from or refund to customers the difference between
its annual uncollectible accounts expense and the amounts collected in rates
annually through a rider mechanism. An equal and offsetting amount has been
recognized in Operating revenues for the periods presented.
The changes in Depreciation and amortization expense consisted of the following:
Increase (Decrease)
2019 vs. 2018
Depreciation expense(a) $ 29
Regulatory asset amortization 6
Regulatory required programs (14 )
Total increase $ 21
__________
(a) Depreciation and amortization increased primarily due to ongoing capital
expenditures.
Interest expense, net for the year endedDecember 31, 2019 compared to the same period in 2018 decreased primarily due to lower outstanding debt. Other, net for the year endedDecember 31, 2019 compared to the same period in 2018 increased primarily due to higher AFUDC equity. Effective income tax rates were 0.0% and 13.8% for the years endedDecember 31, 2019 and 2018, respectively. See Note 13 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. Liquidity and Capital Resources All results included throughout the liquidity and capital resources section are presented on a GAAP basis. The Registrants' operating and capital expenditures requirements are provided by internally generated cash flows from operations 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 112
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Registrants have access to credit facilities with aggregate bank commitments of$10.6 billion . The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the "Credit Matters" section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements. The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and 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, ComEd, PECO, BGE, Pepco, DPL and ACE 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 16 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants' debt and credit agreements. NRC Minimum Funding Requirements 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 9 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT 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 ofDecember 31, 2019 , 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 113
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lives. Additionally, project finance has credit facilities. See Note 16 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. Cash Flows from Operating Activities 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. 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, competitive suppliers, 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 for additional information of regulatory and legal proceedings and proposed legislation. The following table provides a summary of the change in cash provided by (used in) operating activities for the years endedDecember 31, 2019 , 2018 and 2017: 2019 vs. 2018 Variance Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Net income$ 949 $ 774 $ 24 $ 68 $ 47 $ 84 $ 38 $ 27 $ 24 Add (subtract): Non-cash operating activities (778 ) (835 ) (34 ) 43 100 (12 ) (1 ) (26 ) (3 ) Pension and non-pension postretirement benefit contributions (25 ) (36 ) (35 ) - 6 49 3 (1 ) 5 Income taxes (404 ) 495 33 (49 ) (47 ) (18 ) 22 10 4 Changes in working capital and other noncurrent assets and liabilities (1,221 ) (855 ) (71 ) (50 ) (139 ) (118 ) (24 ) (68 ) 3 Option premiums received (paid), net 14 14 - - - - - - - Collateral posted (received), net (520 ) (545 ) 37 - (8 ) - - - -
Net cash flows provided
2018 vs. 2017 Variance
BGE PHI Pepco DPL ACE Net income$ (1,790 ) $ (2,355 ) $ 97 $ 26 $ 6 $ 38 $ 7 $ (1 ) $ (2 ) Add (subtract): Non-cash operating activities 2,133 3,116 (232 ) (12 ) (73 ) (124 ) (17 ) (41 ) (17 ) Pension and non-pension postretirement benefit contributions 22 9 (1 ) (4 ) (1 ) 25 55 2 14 Income taxes 41 (689 ) 370 (19 ) (80 ) (45 ) (94 ) (24 ) 9 Changes in working capital and other noncurrent assets and liabilities 589 359 (49 ) (7 ) 112 288 116 95 18 Option premiums received (paid), net (71 ) (71 ) - - - - - - - Collateral posted (received), net 240 193 37 - 4 - - - -
Net cash flows provided
Changes in Registrants' cash flows from operations for 2019, 2018 and 2017 were
generally consistent with changes in each Registrant's respective results of
operations, as adjusted for non-cash operating activities, and changes in
working capital in the normal course of business. In addition, significant
operating cash flow impacts for the Registrants for 2019, 2018 and 2017 were as
follows:
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• See Note 23 -Supplemental Financial Information of the Combined Notes
to Consolidated Financial Statements and the Registrants' Consolidated
Statement of Cash Flows for additional information on non-cash
operating activity.
• See Note 13 -Income Taxes of the Combined Notes to Consolidated
Financial Statements and the Registrants' Consolidated Statement of
Cash Flows for additional information on income taxes.
• Depending upon whether Generation is in a net mark-to-market liability
or asset position, collateral may be required to be posted with or
collected from its counterparties. In addition, the collateral posting
and collection requirements differ depending on whether the
transactions are on an exchange or in the OTC markets.
Pension and Other Postretirement Benefits Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an Accumulated Benefit Obligation (ABO) basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon's estimated annual qualified pension contributions will be approximately$500 million beginning in 2020. Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements. While other postretirement plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon's management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans. The following table provides all registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to other postretirement plans in 2020: Qualified Pension Plans Non-Qualified Pension Plans OPEB Exelon $ 505 $ 36$ 42 Generation 227 14 16 ComEd 141 2 3 PECO 17 1 - BGE 56 2 16 PHI 22 9 7 Pepco - 2 7 DPL - 1 - ACE 2 - - To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy. 115
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Cash Flows from Investing Activities The following table provides a summary of the change in cash provided by (used in) investing activities for the years endedDecember 31, 2019 , 2018 and 2017: 2019 vs. 2018 Variance Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Capital expenditures$ 346 $ 397 $ 211 $ (90 ) $ (186 ) $ 20 $ 30 $ 16 $ (40 ) Proceeds from NDT fund sales, net 199 199 - - - - - - - Acquisitions of assets and businesses, net 113 113 - - - - - - - Proceeds from sales of assets and businesses (38 ) (38 ) - - - - - - - Changes in intercompany money pool - - - (68 ) - - - - - Other investing activities (46 ) (7 ) - (10 ) (1 ) (7 ) 1 (1 ) (2 ) Net cash flows provided by (used in) investing$ 574 $ 664 $ 211 $ (168 ) $ (187 ) $ 13 $ 31 $ 15 $ (42 ) activities
2018 vs. 2017 Variance Exelon Generation ComEd PECO
BGE PHI Pepco DPL ACE Capital expenditures$ (10 ) $ 17 $ 124 $ (117 ) $ (77 ) $ 21 $ (28 ) $ 64 $ (23 ) Proceeds from NDT fund sales, net 33 33 - - - - - - - Acquisitions of assets and businesses, net 54 54 - - - - - - - Proceeds from sales of assets and businesses (128 ) (128 ) - - - - - - - Changes in intercompany money pool - - - (131 ) - - - - - Other investing activities 188 155 9 5 2 5 2 3 2 Net cash flows provided by (used in) investing$ 137 $ 131 $ 133 $ (243 ) $ (75 ) $ 26 $ (26 ) $ 67 $ (21 ) activities Significant investing cash flow impacts for the Registrants for 2019, 2018 and 2017 were as follows: • Variances in capital expenditures are primarily due to the timing of cash
expenditures for capital projects. Refer below for additional information
on projected capital expenditure spending.
• During 2018, Exelon and Generation had expenditures of
$57 related to the acquisitions of theEverett Marine Terminal and the Handley generating station.
• During 2017, Exelon and Generation had expenditures of
$178 million related to the acquisitions of ConEdison Solutions and the FitzPatrick nuclear generating station.
• During 2018, Exelon and Generation had proceeds of
to the sale of Generation's interest in an electrical contracting
business that primarily installs, maintains and repairs underground and
high-voltage cable transmission and distribution services.
• During 2017, Exelon and Generation had proceeds of $218 million fromsales of long-lived assets, primarily related to the sale back of turbine
equipment.
• Changes in intercompany money pool are driven by short-term borrowing
needs. Refer to more information regarding the intercompany money pool
below.
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Table of Contents Capital Expenditure Spending The Registrants most recent estimates of capital expenditures for plant additions and improvements for 2020 are as follows: (in millions) Transmission Distribution Gas Total Exelon N/A N/A N/A$ 8,175 Generation N/A N/A N/A 1,725 ComEd 475 1,875 N/A 2,350 PECO 125 700 275 1,100 BGE 275 575 475 1,325 Pepco 175 675 N/A 850 DPL 125 225 100 450 ACE 150 225 N/A 375 Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Generation Approximately 45% of projected 2020 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts reflecting additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages), and additional investment in new generation facilities. Generation anticipates that it will fund capital expenditures with internally generated funds and borrowings. Utility Registrants Projected 2020 capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as the Utility Registrants' construction commitments under PJM's RTEP. The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO and BGE submitted their final bi-annual reports to NERC inJanuary 2014 . ComEd and PECO will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd's and PECO's forecasted 2020 capital expenditures above reflect capital spending for remediation to be completed through 2020. BGE, DPL and ACE are complete with their assessments and Pepco has substantially completed its assessment and thus do not expect significant capital expenditures related to this guidance in 2020. The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent. 117
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Cash Flows from Financing Activities The following tables provides a summary of the change in cash provided by (used in) financing activities for the years endedDecember 31, 2019 , 2018 and 2017: 2019 vs. 2018 Variance Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Changes in short-term borrowings, net$ 869 $ 320 $ 130 $ -$ 82 $ 200 $ 28 $ 272 $ (100 ) Long-term debt, net (665 ) (645 ) (110 ) 125 100 (123 ) (51 ) (133 ) 63 Changes in Exelon intercompany money pool - (146 ) - - - 12 - - - Common stock issued from treasury stock - - - - - - - - - Dividends paid on common stock (76 ) - (49 ) (52 ) (15 ) - (44 ) (43 ) (65 ) Distributions to member - 102 - - - (200 ) - - - Contributions from parent/member - (114 ) (250 ) 99 84 13 (6 ) (87 ) 108 Sale of noncontrolling interest - - - - - - - - - Other financing activities 33 4 1 16 (6 ) 4 1 1 2 Net cash flows provided by (used in) financing$ 161 $ (479 ) $ (278 ) $ 188 $ 245 $ (94 ) $ (72 ) $ 10 $ 8 activities 2018 vs. 2017 Variance Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Changes in short-term borrowings, net$ 127 $ 699 $ - $ -$ (74 ) $ 1 $ 11 $ (432 ) $ (77 ) Long-term debt, net 599 (510 ) (65 ) (125 ) 291 418 (3 ) 236 104 Changes in Exelon intercompany money pool - 47 - - - - - - - Common stock issued from treasury stock (1,150 ) - - - - - - - - Dividends paid on common stock (96 ) - (37 ) (18 ) (11 ) - (36 ) 16 9 Distributions to member - (342 ) - - - (15 ) - - - Contributions from parent/member - 53 (151 ) 73 (75 ) (373 ) 5 150 67 Sale of noncontrolling
interest (396 ) (396 ) - - - - - - - Other financing activities (70 ) (1 ) (2 ) (19 ) 3 (7 ) (3 ) (2 ) (3 ) Net cash flows provided by (used in) financing$ (986 ) $ (450 ) $ (255 ) $ (89 ) $ 134 $ 24 $ (26 ) $ (32 ) $ 100 activities Significant investing cash flow impacts for the Registrants for 2019, 2018 and 2017 were as follows: • Changes in short-term borrowings, net, is driven by repayments on and
issuances of notes due in less than 90 days. Refer to Note 16 - Debt and
Credit Agreements of the Combined Notes to Consolidated Financial
Statements for additional information on short-term borrowings.
• Long-term debt, net, varies due to debt issuances and redemptions each
year. Refer to debt issuances and redemptions tables below for more
information.
• Changes in intercompany money pool are driven by short-term borrowing
needs. Refer to more information regarding the intercompany money pool
below.
• Exelon issued common stock in 2017 to fund the PHI merger. Refer to Note
19 - Shareholders' Equity of the Combined Notes to Consolidated Financial
statements for additional information on common stock issuances.
• Exelon's ability to pay dividends on its common stock depends on thereceipt of dividends paid by its operating subsidiaries. The payments of
dividends to Exelon by its subsidiaries in turn depend on their results
of operations and cash flows and other items affecting retained earnings.
See Note 18 - Commitments and Contingencies of the Combined Notes to
Consolidated Financial Statements for additional information on dividend
restrictions. See below for quarterly dividends declared.
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• The change in sale of controlling interest from 2017 to 2018 was
primarily related to cash received in 2017 for the sale of a 49% interest
in EGRP. Refer to Note 22 - Variable Interest Entities of the Combined
Notes to Consolidated Financial Statements for additional information on
sale of controlling interest.
Debt Issuances and Redemptions See Note 16 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants' debt issuances and retirements. Debt activity for 2019, 2018 and 2017 by Registrant was as follows: During 2019, the following long-term debt was issued: Company Type Interest Rate Maturity Amount Use of Proceeds Generation Energy 3.95 % August 31, 2020$ 4 Funding to install Efficiency energy conservation Project measures for the Fort Financing(a) Meade project. Generation Energy 3.46 % May 1, 2020$ 39 Funding to install Efficiency energy conservation Project measures for the Marine Financing(a) Corps. Logistics
Project.
Generation Energy 2.53 % April 30, 2021$ 2 Funding to install Efficiency energy conservation Project measures for the Fort AP Financing(a) Hill project. ComEd First 4.00 % March 1, 2049$ 400 Repay a portion of Mortgage ComEd's outstanding Bonds, Series commercial paper 126 obligations and fund other general corporate purposes. ComEd First 3.20 % November 15, 2049$ 300 Repay a portion of Mortgage ComEd's outstanding Bonds, Series commercial paper 127 obligations and fund other general corporate purposes. PECO First and 3.00 % September 15, 2049$ 325 Repay short-term Refunding borrowings and for Mortgage general corporate Bonds purposes. BGE Senior Notes 3.20 % September 15, 2049 $
400 Repay commercial paper
obligations and for
general corporate
purposes.
Pepco First 3.45 % June 13, 2029 $ 150 Repay existing
Mortgage indebtedness and for
Bonds general corporate
purposes.
Pepco Unsecured 1.70 % September 1, 2022 $ 110 Refinance existing
Tax-Exempt indebtedness.
Bonds
DPL First 4.14 % December 12, 2049 $ 75 Repay existing
Mortgage indebtedness and for
Bonds general corporate
purposes.
ACE First 3.50 % May 21, 2029 $ 100 Repay existing
Mortgage indebtedness and for
Bonds general corporate
purposes.
ACE First 4.14 % May 21, 2049 $ 50 Repay existing
Mortgage indebtedness and for
Bonds general corporate
purposes.
__________(a) For Energy Efficiency Project Financing, the maturity dates represent the
expected date of project completion, upon which the respective customer
assumes the outstanding debt.
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During 2018, the following long term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds Generation Energy 3.72 % March 31, 2019$ 4 Funding to install Efficiency energy conservation Project measures for the Financing(a) Smithsonian Zoo project. Generation Energy 3.17 % January 31, 2019$ 1 Funding to install Efficiency energy conservation Project measures in Brooklyn, Financing(a) NY. Generation Energy 2.61 % September 30, 2018$ 5 Funding to install Efficiency energy conservation Project measures for the Financing(a) Pensacola project. Generation Energy 4.17 % January 31, 2019$ 1 Funding to install Efficiency energy conservation Project measures for the General Financing(a) Services Administration Philadelphia project. Generation Energy 4.26 % May 31, 2019$ 3 Funding to install Efficiency energy conservation Project measures for the Financing(a) National Institutes of Health Multi-Buildings Phase II project. ComEd First 4.00 % March 1, 2048$ 800 Refinance one series of Mortgage maturing first mortgage Bonds, Series bonds, to repay a 124 portion of ComEd's outstanding commercial paper obligations and to fund general corporate purposes. ComEd First 3.70 % August 15, 2028 $
550 Repay a portion of
Mortgage ComEd's outstanding
Bonds, Series commercial paper
125 obligations and for
general corporate
purposes.
PECO First and 3.90 % March 1, 2048 $ 325 Refinance a portion of
Refunding maturing mortgage bonds.
Mortgage
Bonds
PECO Loan 2.00 % June 20, 2023 $ 50 Funding to implement
Agreement Electric Long-term
Infrastructure
Improvement Plan.
PECO First and 3.90 % March 1, 2048 $ 325 Satisfy short-term
Refunding borrowings from the
Mortgage Exelon intercompany
Bonds money pool and for
general corporate
purposes.
BGE Senior Notes 4.25 % September 15, 2048 $ 300 Repay commercial paper
obligations and for
general corporate
purposes.
Pepco First 4.27 % June 15, 2048 $ 100 Repay outstanding
Mortgage commercial paper and for
Bonds general corporate
purposes.
Pepco First 4.31 % November 1, 2048 $ 100 Repay outstanding
Mortgage commercial paper and for
Bonds general corporate
purposes.
DPL First 4.27 % June 15, 2048 $ 200 Repay outstanding
Mortgage commercial paper and for
Bonds general corporate
purposes.
ACE First 4.00 % October 15, 2028 $ 350 Refinance ACE's 7.75%
Mortgage First Mortgage Bonds due
Bonds November 15, 2018,
reduce short-term
borrowings and for
general corporate
purposes.
__________
(a) For Energy Efficiency Project Financing, the maturity dates represent the
expected date of project completion, upon which the respective customer
assumes the outstanding debt.
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During 2017, the following long term-debt was issued:
Company Type Interest Rate Maturity Amount
Use of Proceeds
Exelon Junior 3.50 % June 1, 2022 $ 1,150 Refinance Exelon's
Corporate Subordinated Junior Subordinated
Notes Notes issued in June
2014.Generation Albany Green LIBOR + 1.25% November 17, 2017 $ 14
Albany Green Energy
Energy biomass generation
Project development.
Financing(a)
Generation Energy 3.90 % February 1, 2018 $ 19 Funding to install
Efficiency energy conservation
Project measures for the Naval
Financing(a) Station Great Lakes
project.
Generation Energy 3.72 % May 1, 2018 $ 5 Funding to install
Efficiency energy conservation
Project measures for the
Financing(a) Smithsonian Zoo project.
Generation Energy 2.61 % September 30, 2018 $ 13 Funding to install
Efficiency energy conservation
Project measures for the
Financing(a) Pensacola project.
Generation Energy 3.53 % April 1, 2019 $ 8 Funding to install
Efficiency energy conservation
Project measures for the State
Financing(a) Department project.
Generation Senior Notes 2.95 % January 15, 2020 $ 250 Repay outstanding
commercial paper
obligations and for
general corporate
purposes.
Generation Senior Notes 3.40 % March 15, 2020 $ 500 Repay outstanding
commercial paper
obligations and for
general corporate
purposes.Generation ExGen Texas LIBOR + 4.75% September 18, 2021 $ 6
General corporate
Power purposes.
Nonrecourse
Debt(b)(c)
Generation ExGen LIBOR + 3.00% November 30, 2024 $ 850 General corporate
Renewables purposes.
IV,
Nonrecourse
Debt(b)
ComEd First 2.95 % August 15, 2027 $ 350 Refinance maturing
Mortgage mortgage bonds, repay a
Bonds, Series portion of ComEd's
122 outstanding commercial
paper obligations and
for general corporate
purposes.
ComEd First 3.75 % August 15, 2047 $ 650 Refinance maturing
Mortgage mortgage bonds, repay a
Bonds, Series portion of ComEd's
123 outstanding commercial
paper obligations and
for general corporate
purposes.
PECO First and 3.70 % September 15, 2047 $ 325 General corporate
Refunding purposes.
Mortgage
Bonds
BGE Senior Notes 3.75 % August 15, 2047 $ 300 Redeem $250 million in
principal amount of the
6.20% Deferrable
Interest Subordinated
Debentures due October
15, 2043 issued by BGE's
affiliate BGE Capital
Trust II, repay
commercial paper
obligations and for
general corporate
purposes.
Pepco Energy 3.30 % December 15, 2017 $ 2 Funding to install
Efficiency energy conservation
Project measures for the DOE
Financing(a) Germantown project.
Pepco First 4.15 % March 15, 2043 $ 200 Funding to repay
Mortgage outstanding commercial
Bonds paper and for general
corporate purposes.
__________(a) For Energy Efficiency Project Financing, the maturity dates represent the
expected date of project completion, upon which the respective customer
assumes the outstanding debt.
(b) See Note 16 - Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements for additional information of nonrecourse
debt.
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(c) As a result of the bankruptcy filing for EGTP on November 7, 2017, the
nonrecourse debt was deconsolidated from Exelon's and Generation's
consolidated financial statements. See Note 2 - Mergers, Acquisitions and
Dispositions of the Combined Notes to Consolidated Financial Statements for
additional information.
During 2019, the following long-term debt was retired and/or redeemed:
Company(a) Type Interest Rate Maturity Amount
Long-Term Software License
Exelon Agreement 3.95% May 1, 2024 $ 18
Antelope Valley DOE
Generation Nonrecourse Debt(b) 2.33% - 3.56% January 5, 2037 $ 23 Generation Kennett Square Capital Lease 7.83% September 20, 2020 $ 5
Continental Wind Nonrecourse
Generation Debt(b) 6.00% February 28, 2033 $ 32
Generation Pollution control notes 2.50% March 1, 2019 $ 23
Renewable Power Generation
Generation Nonrecourse Debt(b) 4.11% March 31, 2035 $ 10
Energy Efficiency Project
Generation Financing 3.46% April 30, 2019 $ 39
ExGen Renewables IV
Generation Nonrecourse debt(b) 3mL +3% November 30, 2024 $ 38
Hannie Mae, LLC Defense
Generation Financing 4.12% November 30, 2019 $ 1
Energy Efficiency Project
Generation Financing 3.72% July 31, 2019 $ 25
Generation NUKEM 3.15% September 30, 2020 $ 36 Generation SolGen Nonrecourse Debt(b) 3.93% September 30, 2036 $ 6
Energy Efficiency Project
Generation Financing 4.17% October 31, 2019 $ 1
Energy Efficiency Project
Generation Financing 3.53% March 31, 2020 $ 1
Energy Efficiency Project
Generation Financing 4.26% September 30, 2019 $ 1
Generation Senior Notes 5.20% October 1, 2019 $ 600
Generation Dominion Federal Corp 3.17% October 31, 2019 $ 18
Fort Detrick Project
Generation Financing 3.55% October 31, 2019 $ 1
ComEd First Mortgage Bonds 2.15% January 15, 2019 $ 300
Pepco Secured Tax-Exempt Bonds 6.20% - 7.49% 2021 - 2022 $ 110
DPL Medium Term Notes, Unsecured 7.61% December 2, 2019 $ 12
ACE Transition Bonds 5.55% October 20, 2023 $ 18
__________
(a) On January 15, 2020, Generation redeemed $1 billion of 2.95% Senior Notes at
maturity.
(b) See Note 16 - Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements for additional information of nonrecourse
debt.
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During 2018, the following long-term debt was retired and/or redeemed:
Company Type Interest Rate Maturity Amount Exelon Long-Term Software License Corporate Agreement 3.95% May 1,
2024 $ 6
Naval Station Great Lakes
Generation Project Financing 3.90% June 30, 2018 $ 41
Smithsonian Zoo Project
Generation Financing 3.72% March 31, 2019 $ 1
Generation Pensacola Project Financing 2.61% September 30, 2018 $ 21
Generation Fort Detrick Project Financing 3.55% June 30, 2019 $ 19
Generation Holyoke Nonrecourse Debt(a) 5.25% December 31, 2031 $ 1
Generation SolGen Nonrecourse Debt(a) 3.93% September 30, 2036 $ 10
Antelope Valley DOE Nonrecourse
Generation Debt(a) 2.29% - 3.56% January 5, 2037 $ 22
Continental Wind Nonrecourse
Generation Debt(a) 6.00% February 28, 2033 $ 33
Renewable Power Generation
Generation Nonrecourse Debt(a) 4.11% March 31, 2035 $ 11
Generation Kennett Square Capital Lease 7.83% September 20, 2020 $ 4
ExGen Renewables IV Nonrecourse
Generation Debt(a) 3mL+300 bps November 30, 2024 $ 16
Generation NUKEM 3.15% - 3.35% 2018 - 2020 $ 43
ComEd First Mortgage Bonds 5.80% March 15, 2018 $ 700
ComEd Notes 6.95% July 15, 2018 $ 140
PECO First Mortgage Bonds 5.35% March 1, 2018 $ 500
DPL Medium Term Notes, Unsecured 6.81% January 9, 2018 $ 4
Pepco Notes 3.30% August 31, 2018 $ 5
Pepco Third Party Financing 7.28-7.99% 2021 - 2023 $ 1
ACE First Mortgage Bonds 7.75% November15, 2018 $ 250 ACE Transition Bonds 5.05% - 5.55% 2020 - 2023 $ 31 __________
(a) See Note 16 - Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements for additional information of nonrecourse
debt.
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During 2017, the following long-term debt was retired and/or redeemed:
Company Type Interest Rate Maturity Amount Exelon Long-Term Software License Corporate Agreement 3.95% May 1, 2024 $ 24 Exelon Corporate Senior Notes 1.55% June 9, 2017 $ 550 Generation Senior Notes - Exelon Wind 2.00% July 31, 2017 $ 1 Generation CEU Upstream Nonrecourse Debt(a) LIBOR + 2.25% January 14, 2019 $ 6 Generation SolGen Nonrecourse Debt(a) 3.93% September
30, 2036 $ 2
Antelope Valley DOE Nonrecourse
Generation Debt(a) 2.29% - 3.56% January 5, 2037 $ 22
Generation Kennett Square Capital Lease 7.83% September 20, 2020 $ 2
Continental Wind Nonrecourse
Generation Debt(a) 6.00% February 28, 2033 $ 31
Generation PES - PGOV Notes Payable 6.70-7.60% 2017 - 2018 $ 1
ExGen Texas Power Nonrecourse
Generation Debt (a)(b) LIBOR + 4.75% September 18, 2021 $ 665
Renewable Power Generation
Generation Nonrecourse Debt(a) 4.11% March 31, 2035 $ 14
Generation NUKEM 3.25% - 3.35% June 30, 2018 $ 23
ExGen Renewables I, Nonrecourse
Generation Debt(a) LIBOR + 4.25% February 6, 2021 $ 233
Generation Senior Notes 6.20% October 1, 2017 $ 700
Albany Green Energy Project
Generation Financing LIBOR + 1.25% November 17, 2017 $ 212
ComEd First Mortgage Bonds 6.15% September 15, 2017 $ 425
BGE Rate Stabilization Bonds 5.82% April 1, 2017 $ 41
Capital Trust Preferred
BGE Securities 6.20% October 15, 2043 $ 258
PHI Senior Notes 6.13% June 1, 2017 $ 81
DPL Medium Term Notes, Unsecured 7.56% - 7.58% February 1, 2017 $ 14
DPL Variable Rate Demand Bonds Variable October 1, 2017 $ 26
Pepco Third Party Financing 6.97% - 7.99% 2018 - 2022 $ 1
ACE Transition Bonds 5.05% - 5.55% 2020 - 2023 $ 35
__________
(a) See Note 16 - Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements for additional information of nonrecourse
debt.
(b) As a result of the bankruptcy filing for EGTP on November 7, 2017, the
nonrecourse debt was deconsolidated from Exelon's and Generation's
consolidated financial statements. See Note 2 - Mergers, Acquisitions and
Dispositions for additional information.
From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets.
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Table of Contents Dividends
Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2019 and for the first quarter of 2020 were as follows:
Shareholder of Cash per
Period Declaration Date Record Date Dividend Payable Date Share(a)
February 20,
First Quarter 2019 February 5, 2019 2019 March 8, 2019 $ 0.3625
Second Quarter 2019 April 30, 2019 May 15, 2019 June 10, 2019 $ 0.3625
Third Quarter 2019 July 30, 2019 August 15, 2019 September 10, 2019 $ 0.3625
November 15,
Fourth Quarter 2019 November 1, 2019 2019 December 10, 2019 $ 0.3625
February 20,
First Quarter 2020 January 28, 2020 2020 March 10, 2020 $ 0.3825
___________
(a) Exelon's Board of Directors approved an updated dividend policy providing an
increase of 5% each year for the period covering 2018 through 2020, beginning
with the March 2018 dividend.
Other
For the year ended December 31, 2019, other financing activities primarily
consists of debt issuance costs. See Note 16 - Debt and Credit Agreements of the
Combined Notes to Consolidated Financial Statements' for additional information.
Credit Matters
Market Conditions
The Registrants fund liquidity needs for capital investment, working capital,
energy hedging and other financial commitments through cash flows from
continuing operations, public debt offerings, commercial paper markets and
large, diversified credit facilities. The credit facilities include $10.6
billion in aggregate total commitments of which $7.4 billion was available to
support additional commercial paper as of December 31, 2019, and of which no
financial institution has more than 7% of the aggregate commitments for the
Registrants. The Registrants had access to the commercial paper market during
2019 to fund their short-term liquidity needs, when necessary. The Registrants
routinely review the sufficiency of their liquidity position, including
appropriate sizing of credit facility commitments, by performing various stress
test scenarios, such as commodity price movements, increases in margin-related
transactions, changes in hedging levels and the impacts of hypothetical credit
downgrades. The Registrants have continued to closely monitor events in the
financial markets and the financial institutions associated with the credit
facilities, including monitoring credit ratings and outlooks, credit default
swap levels, capital raising and merger activity. See PART I. ITEM 1A. RISK
FACTORS for additional information regarding the effects of uncertainty in the
capital and credit markets.
The Registrants believe their cash flow from operating activities, access to
credit markets and their credit facilities provide sufficient liquidity. If
Generation lost its investment grade credit rating as of December 31, 2019, it
would have been required to provide incremental collateral of $1.5 billion to
meet collateral obligations for derivatives, non-derivatives, normal purchases
and normal sales contracts and applicable payables and receivables, net of the
contractual right of offset under master netting agreements, which is well
within the $4.2 billion of available credit capacity of its revolver.
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The following table presents the incremental collateral that each Utility
Registrant would have been required to provide in the event each Utility
Registrant lost its investment grade credit rating at December 31, 2019 and
available credit facility capacity prior to any incremental collateral at
December 31, 2019:
Available Credit
Facility Capacity
PJM Credit Prior to Any
Policy Other Incremental Incremental
Collateral Collateral Required(a) Collateral
ComEd $ 11 $ - $ 868
PECO - 44 600
BGE 11 50 524
Pepco 11 - 218
DPL 4 11 244
ACE - - 230
__________(a) Represents incremental collateral related to natural gas procurement
contracts.
Exelon Credit Facilities
Exelon Corporate, ComEd and BGE meet their short-term liquidity requirements
primarily through the issuance of commercial paper. Generation and PECO meet
their short-term liquidity requirements primarily through the issuance of
commercial paper and borrowings from the Exelon intercompany money pool. Pepco,
DPL, and ACE meet their short-term liquidity requirements primarily through the
issuance of commercial paper and borrowings from the PHI intercompany money
pool. PHI Corporate meets its short-term liquidity requirements primarily
through the issuance of short-term notes and the Exelon intercompany money pool.
The Registrants may use their respective credit facilities for general corporate
purposes, including meeting short-term funding requirements and the issuance of
letters of credit.
See Note 16 - Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements for additional information of the Registrants' credit
facilities and short term borrowing activity.
Other Credit Matters
Capital Structure. At December 31, 2019, the capital structures of the
Registrants consisted of the following:
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Long-term
debt 50 % 31 % 44 % 44 % 47 % 40 % 49 % 49 % 50 %
Long-term
debt to
affiliates(a) 1 % 4 % - % 2 % - % - % - % - % - %
Common equity 47 % - % 55 % 54 % 52 % - 50 % 49 % 47 %
Member's
equity - % 64 % - % - % - % 59 % - - -
Commercial
paper and
notes payable 2 % 1 % 1 - % 1 % 1 % 1 % 2 % 3 %
__________(a) Includes approximately $390 million, $205 million and $184 million owed to
unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These
special purpose entities were created for the sole purposes of issuing
mandatorily redeemable trust preferred securities of ComEd and PECO. See Note
22 - Variable Interest Entities of the Combined Notes to Consolidated
Financial Statements for additional information regarding the authoritative
guidance for VIEs.
Security Ratings
The Registrants' access to the capital markets, including the commercial paper
market, and their respective financing costs in those markets, may depend on the
securities ratings of the entity that is accessing the capital markets.
The Registrants' borrowings are not subject to default or prepayment as a result
of a downgrading of securities, although such a downgrading of a Registrant's
securities could increase fees and interest charges under that Registrant's
credit agreements.
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As part of the normal course of business, the Registrants enter into contracts
that contain express provisions or otherwise permit the Registrants and their
counterparties to demand adequate assurance of future performance when there are
reasonable grounds for doing so. In accordance with the contracts and applicable
contracts law, if the Registrants are downgraded by a credit rating agency, it
is possible that a counterparty would attempt to rely on such a downgrade as a
basis for making a demand for adequate assurance of future performance, which
could include the posting of collateral. See Note 15 - Derivative Financial
Instruments of the Combined Notes to Consolidated Financial Statements for
additional information on collateral provisions.
Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more
favorable to the borrowing participants than the cost of external financing,
both Exelon and PHI operate an intercompany money pool. Maximum amounts
contributed to and borrowed from the money pool by participant and the net
contribution or borrowing as of December 31, 2019, are presented in the
following tables:
As of
Exelon Intercompany Money Pool For the Year Ended December 31, 2019
December 31, 2019
Maximum Maximum
Contributed (borrowed) Contributed Borrowed Contributed (Borrowed)
Exelon Corporate $ 467 $ - $ 121
Generation 212 (235 ) -
PECO 164 (85 ) 68
BSC 18 (383 ) (232 )
PHI Corporate - (12 ) (12 )
PCI 60 - 55
As of
PHI Intercompany Money Pool For the Year Ended December 31, 2019 December 31, 2019
Maximum Maximum
Contributed (borrowed) Contributed Borrowed Contributed (Borrowed)
Pepco $ 63 $ - $ -
DPL 3 (45 ) -
ACE - (29 ) -
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Shelf Registration Statements.Exelon, Generation , ComEd, PECO, BGE, Pepco, DPL and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with theSEC , that will expire in August 2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions. Regulatory Authorizations. ComEd, PECO, BGE, Pepco, DPL and ACE are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows: Short-term Financing Authority(a)(b)
Long-term Financing Authority(a)
Commission Expiration Date Amount Commission Expiration Date Amount (c)
ComEd(c) FERC December 31, 2021 $ 2,500 ICC 2021 & 2023 $ 1,893
PECO FERC December 31, 2021 1,500 PAPUC December 31, 2021 1,575
BGE FERC December 31, 2021 700 MDPSC N/A -
Pepco FERC December 31, 2021 500 MDPSC / DCPSC December 31, 2022 1,200
DPL FERC December 31, 2021 500 MDPSC / DPSC December 31, 2022 475
ACE NJBPU December 31, 2021 350 NJBPU December 31, 2020 200
__________
(a) Generation currently has blanket financing authority it received from
connection with its market-based rate authority.
(b) On October 15, 2019, ComEd, BGE, Pepco and DPL filed applications with
and on September 12, 2019, ACE filed an application with NJBPU for renewal of
their short-term financing authority through December 31, 2021. ComEd, BGE,
Pepco and DPL received approval on December 13, 2019 and ACE received
approval on December 6, 2019.
(c) As of December 31, 2019, ComEd had $393 million in new money long-term debt
financing authority from the ICC with an expiration date of August 1, 2021.
On January 22, 2020, ComEd had an additional $1.5 billion available in new
money long-term debt financing authority from the ICC with an effective date
of February 1, 2020 and an expiration date of February 1, 2023.
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Contractual Obligations and Off-Balance Sheet Arrangements
The following tables summarize the Registrants' future estimated cash payments
as of December 31, 2019 under existing contractual obligations, including
payments due by period.
Exelon
Payment due within
2021 - 2023 - 2025
Total 2020 2022 2024 and beyond
Long-term debt(a) $ 35,910 $ 4,704 $ 4,594 $ 2,442 $ 24,170
Interest payments on long-term
debt(b) 22,608 1,356 2,586 2,357 16,309
Finance leases 40 6 11 9 14
Operating leases(c) 1,361 144 267 197 753Purchase power obligations(d) 1,201 312 672
198 19
Fuel purchase agreements(e) 6,217 1,209 1,852 1,380 1,776
Electric supply procurement 2,049 1,310 731 8 -
Long-term renewable energy and REC
commitments 2,284 254 534 448 1,048
Other purchase obligations(f) 8,308 6,189 1,139
274 706
DC PLUG obligation 130 30 60 40 -
SNF obligation 1,199 - - - 1,199
ZEC commitments 1,313 164 328 328 493
Pension contributions(g) 3,030 505 1,010 1,010 505Total contractual obligations $ 85,650 $ 16,183 $ 13,784 $ 8,691 $ 46,992
__________
(a) Includes amounts from ComEd and PECO financing trusts.
(b) Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2019 and do not reflect anticipated
future refinancing, early redemptions or debt issuances. Variable rate
interest obligations are estimated based on rates as of December 31, 2019.
Includes estimated interest payments due to ComEd and PECO financing trusts.
(c) Capacity payments associated with contracted generation lease agreements are
net of sublease and capacity offsets of $143 million, $98 million, $55
million, $44 million, $44 million and $223 million for 2020, 2021, 2022,
2023, 2024 and thereafter, respectively and $607 million in total.
(d) Purchase power obligations primarily include expected payments for REC
purchases and payments associated with contracted generation agreements,
which may be reduced based on plant availability. Expected payments exclude
payments on renewable generation contracts that are contingent in nature.
(e) Represents commitments to purchase nuclear fuel, natural gas and related
transportation, storage capacity and services.
(f) Represents the future estimated value at December 31, 2019 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between the Registrants and third-parties for the provision of services
and materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
(g) These amounts represent Exelon's expected contributions to its qualified
pension plans. Qualified pension contributions for years after 2025 are not
included.
Generation
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Payment due within
2021 - 2023 - 2025
Total 2020 2022 2024 and beyond
Long-term debt $ 7,938 $ 3,180 $ 1,024 $ 792 $ 2,942
Interest payments on long-term debt(a) 3,575 253 480 424 2,418
Finance leases 5 2 2 1 -
Operating leases(b) 809 60 122 109 518
Purchase power obligations(c) 1,201 312 672 198 19
Fuel purchase agreements(d) 5,056 999 1,536 1,189 1,332
Other purchase obligations(e) 2,536 1,516 230 126 664
SNF obligation 1,199 - - - 1,199
Total contractual obligations $ 22,319 $ 6,322 $ 4,066 $ 2,839 $ 9,092
__________
(a) Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2019 and do not reflect anticipated
future refinancing, early redemptions or debt issuances. Variable rate
interest obligations are estimated based on rates as of December 31, 2019.
(b) Capacity payments associated with contracted generation lease agreements are
net of sublease and capacity offsets of $143 million, $98 million, $55
million, $44 million, $44 million and $223 million for 2020, 2021, 2022,
2023, 2024 and thereafter, respectively and $607 million in total.
(c) Purchase power obligations primarily include expected payments for REC
purchases and capacity payments associated with contracted generation
agreements, which may be reduced based on plant availability. Expected
payments exclude payments on renewable generation contracts that are
contingent in nature.
(d) Primarily represents commitments to purchase fuel supplies for nuclear and
fossil generation, including those related to CENG.
(e) Represents the future estimated value at December 31, 2019 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between Generation and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
ComEd
Payment due within
2021 - 2023 - 2025
Total 2020 2022 2024 and beyond
Long-term debt(a) $ 8,783 $ 500 $ 350 $ 250 $ 7,683
Interest payments on long-term
debt(b) 6,918 345 674 665 5,234
Finance leases 8 - - - 8
Operating leases 12 3 6 2 1
Electric supply procurement 617 403 214 - -
Long-term renewable energy and REC
commitments 1,986 222 470 384 910
Other purchase obligations(c) 1,262 1,219 36 5 2
ZEC commitments 1,313 164 328 328 493
Total contractual obligations $ 20,899 $ 2,856 $ 2,078 $ 1,634 $ 14,331
__________
(a) Includes amounts from ComEd financing trust.
(b) Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2019 and do not reflect anticipated
future refinancing, early redemptions or debt issuances. Variable rate
interest obligations are estimated based on rates as of December 31, 2019.
Includes estimated interest payments due to the ComEd financing trust.
(c) Represents the future estimated value at December 31, 2019 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between ComEd and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
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PECO
Payment due within
2021 - 2023 - 2025
Total 2020 2022 2024 and beyond
Long-term debt(a) $ 3,634 $ - $ 650 $ 50 $ 2,934
Interest payments on long-term debt(b) 2,721 141 274 254 2,052
Operating leases 1 - 1 - -
Fuel purchase agreements(c) 335 116 154 31 34
Electric supply procurement 552 441 111 - -
Other purchase obligations(d) 834 727 107 - -
Total contractual obligations $ 8,077 $ 1,425 $ 1,297 $
335 $ 5,020
__________
(a) Includes amounts from PECO financing trusts.
(b) Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2019 and do not reflect anticipated
future refinancing, early redemptions or debt issuances. Includes estimated
interest payments due to the PECO financing trust.
(c) Represents commitments to purchase natural gas and related transportation,
storage capacity and services.
(d) Represents the future estimated value at December 31, 2019 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between PECO and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
BGE
Payment due within
2021 - 2023 - 2025
Total 2020 2022 2024 and beyond
Long-term debt $ 3,300 $ - $ 550 $ 300 $ 2,450
Interest payments on long-term debt(a) 2,241 126 238 203 1,674
Operating leases 100 34 47 1 18
Fuel purchase agreements(b) 522 60 94 92 276
Electric supply procurement 1,050 631 419 - -
Other purchase obligations(c) 1,014 868 141 3 2
Total contractual obligations $ 8,227 $ 1,719 $ 1,489 $
599 $ 4,420
__________
(a) Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2019 and do not reflect anticipated
future refinancing, early redemptions or debt issuances.
(b) Represents commitments to purchase natural gas and related transportation,
storage capacity and services.
(c) Represents the future estimated value at December 31, 2019 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between BGE and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
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PHI
Payment due within
2021 - 2023 - 2025
Total 2020 2022 2024 and beyond
Long-term debt $ 5,967 $ 98 $ 571 $ 1,049 $ 4,249
Interest payments on long-term
debt(a) 4,150 269 512 463 2,906
Finance leases 28 5 8 8 7
Operating leases 346 42 79 72 153
Fuel purchase agreements(b) 304 34 68 68 134
Long-term renewable energy and REC
commitments 298 32 64 64 138
Electric supply procurement 1,787 1,040 730 17 -
Other purchase obligations(c) 1,181 959 184
6 32
DC PLUG obligation 130 30 60 40 -
Total contractual obligations $ 14,219 $ 2,514 $ 2,284 $ 1,795 $ 7,626
__________
(a) Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2019 and do not reflect anticipated
future refinancing, early redemptions or debt issuances.
(b) Represents commitments to purchase natural gas and related transportation,
storage capacity and services.
(c) Represents the future estimated value at December 31, 2019 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between PHI and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
Pepco
Payment due within
2021 - 2023 - 2025
Total 2020 2022 2024 and beyond
Long-term debt $ 2,886 $ 1 $ 311 $ 399 $ 2,175
Interest payments on long-term debt(a) 2,385 138 271 249 1,727
Finance leases 11 1 2 3 5
Operating leases 70 8 16 12 34
Electric supply procurement 803 445 341 17 -
Other purchase obligations(b) 663 489 145 4 25
DC PLUG obligation 130 30 60 40 -
Total contractual obligations $ 6,959 $ 1,113 $ 1,148 $
727 $ 3,971
__________
(a) Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2019 and do not reflect anticipated
future refinancing, early redemptions or debt issuances.
(b) Represents the future estimated value at December 31, 2019 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between Pepco and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
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DPL
Payment due within
2021 - 2023 - 2025
Total 2020 2022 2024 and beyond
Long-term debt $ 1,568 $ 78 $ - $ 500 $ 990
Interest payments on long-term
debt(a) 1,087 60 120 99 808
Finance leases 10 2 4 3 1
Operating leases 91 11 21 18 41
Fuel purchase agreements(b) 304 34 68 68 134
Long-term renewable energy and
associated REC commitments 298 32 64 64 138
Electric supply procurement 458 288 170 - -
Other purchase obligations(c) 280 262 18 - -
Total contractual obligations $ 4,096 $ 767 $ 465 $ 752 $ 2,112
__________
(a) Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2019 and do not reflect anticipated
future refinancing, early redemptions or debt issuances.
(b) Represents commitments to purchase natural gas and related transportation,
storage capacity and services.
(c) Represents the future estimated value at December 31, 2019 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between DPL and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
ACE
Payment due within
2021 - 2023 - 2025
Total 2020 2022 2024 and beyond
Long-term debt $ 1,327 $ 19 $ 260 $ 150 $ 898
Interest payments on long-term debt (a) 503 57 93 87 266
Finance leases 8 1 2 2 3
Operating leases 20 5 8 5 2
Electric supply procurement 526 307 219 - -
Other purchase obligations(b) 200 185 15 - -
Total contractual obligations $ 2,584 $ 574 $ 597 $ 244 $ 1,169
__________
(a) Interest payments are estimated based on final maturity dates of debt
securities outstanding at December 31, 2019 and do not reflect anticipated
future refinancing, early redemptions or debt issuances.
(b) Represents the future estimated value at December 31, 2019 of the cash flows
associated with all contracts, both cancellable and non-cancellable, entered
into between ACE and third-parties for the provision of services and
materials, entered into in the normal course of business not specifically
reflected elsewhere in this table. These estimates are subject to significant
variability from period to period.
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See Note 18 - Commitments and Contingencies and Note 3 - Regulatory Matters of
the Combined Notes to Consolidated Financial Statements for additional
information of the Registrants' other commitments potentially triggered by
future events. Additionally, see below for where to find additional information
regarding certain contractual obligations in the Combined Notes to the
Consolidated Financial Statements:
Location within Notes to the Consolidated Financial
Item Statements
Finance Leases Note 10 - Leases
Operating Leases Note 10 - Leases
DC PLUG obligation Note 3 - Regulatory Matters
ZEC Commitments Note 3 - Regulatory Matters
Note 3 - Regulatory Matters & Note 15 - Derivative
REC Commitments Financial Instruments
Long-term debt Note 16 - Debt and Credit Agreements
Interest payments on
long-term debt Note 16 - Debt and Credit Agreements
Pension contributions Note 14 - Retirement Benefits
SNF obligation Note 18 - Commitments and Contingencies© Edgar Online, source
