Completed Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Approved Revenue Requirement (Decrease) Increase			Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois (Electric)	April 16, 2018	$	(23	)	$	(24	)	8.69	%	December 4, 2018	January 1, 2019
PECO - Pennsylvania (Electric)	March 29, 2018	$	82		$	25		N/A		December 20, 2018	January 1, 2019
BGE - Maryland (Natural Gas)	June 8, 2018 (amended October 12, 2018)	$	61		$	43		9.8	%	January 4, 2019	January 4, 2019
ACE - New Jersey (Electric)	August 21, 2018 (amended November 19, 2018)	$	122		$	70		9.6	%	March 13, 2019	April 1, 2019

Pending Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement Increase (Decrease)			Requested ROE		Expected Approval Timing
Pepco - Maryland (Electric)	January 15, 2019 (amended May 16, 2019)	$	27		10.3	%	Third quarter of 2019
ComEd - Illinois (Electric)	April 8, 2019	$	(6	)	8.91	%	December 2019
BGE - Maryland (Electric)	May 24, 2019	$	74		10.3	%	December 2019
BGE - Maryland (Natural Gas)	May 24, 2019	$	59		10.3	%	December 2019
Pepco - District of Columbia (Electric)	May 30, 2019	$	162		10.3	%	Second quarter of 2020

Transmission Formula Rate

The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's ~~2018~~2019 annual electric transmission formula rate updates.

2018
Annual Transmission Updates^(a)(b)
ComEd BGE Pepco DPL ACE
Initial revenue requirement (decrease) increase $ (44 ) $ 10
$ 6
$ 14
$ 4
Annual reconciliation increase (decrease) 18
4
2
13
(4 )
Dedicated facilities increase^(c)
—
12
—
—
—
Total revenue requirement (decrease) increase $ (26 ) $ 26
$ 8
$ 27
$ —

Allowed return on rate base^(d)
8.32 % 7.61 % 7.82 % 7.29 % 8.02 %
Allowed ROE^(e)
11.50 % 10.50 % 10.50 % 10.50 % 10.50 %



Registrant	Initial Revenue Requirement Increase (Decrease)			Annual Reconciliation Increase (Decrease)			Total Revenue Requirement Increase (Decrease)			Allowed Return 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	%

~~_________~~


~~(a)~~	~~All rates are effective June 2018, subject to review by the FERC and other parties, which is due by fourth quarter 2018.~~

~~(b)~~

The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See further discussion above.


~~(c)~~	~~BGE's transmission revenues include a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to a specifically designated load by BGE.~~


~~(d)~~	~~Represents the weighted average debt and equity return on transmission rate bases.~~

~~(e)~~

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.

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. ~~The~~PECO’s initial formula rate filing ~~includes~~included a requested increase of $22 million to PECO’s annual transmission ~~revenues and~~revenue requirement, which reflected a ~~requested rate of return on common equity~~ROE of 11%, inclusive of a 50 basis point adder for being a member of a ~~regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017.~~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.

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.

On ~~May 4,~~July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement is not expected to have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is not expected prior to the ~~Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge.~~fourth quarter of 2019. PECO cannot predict the ~~final~~ outcome of this proceeding, or the transmission formula FERC may approve.

Early Plant Retirements and Divestitures

Oyster Creek. Generation permanently ceased generation operations at Oyster Creek in September 2018. On ~~May 11,~~July 31, 2018, ~~pursuant to~~Generation entered into an agreement with Holtec International and its wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the ~~transmission formula rate request discussed above, PECO made its first annual formula rate update,~~sale and decommissioning of Oyster Creek. The sale was completed on July 1, 2019. Exelon and Generation expect the loss on the sale, which included a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.

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~~Winter Storm-Related Costs~~

During March 2018 there were powerful nor'easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the region that interrupted electric service delivery to customers in PECO's, BGE's, Pepco's, DPL's and ACE's service territories. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in incremental operating and maintenance expense and incremental capital expenditureswill be recognized in the ~~first~~third quarter, of 2018 for PECO, BGE, PHI, Pepco, DPL and ACE. In addition, PHI, Pepco, DPL and ACE recorded regulatory assets for amounts that are probable of recovery through customer rates. The impacts recorded by the Registrants for the nine months ended September 30, 2018 are presented below:

(in millions)
Customer Outages Incremental Operating & Maintenance Incremental Capital Expenditures
Exelon 1,727,000
$ 88
^(b)
$ 89
PECO 750,000
53
35
BGE 425,000
31
15
PHI^(a)
552,000
4
^(b)
39
Pepco 182,000
2
^(b)
4
DPL 138,000
2
^(b)
4
ACE 232,000
—
^(b)
31

~~________~~


~~(a)~~	~~PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE.~~


~~(b)~~	~~Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $28 million, $28 million, $7 million, $1 million and $20 million, respectively.~~

~~Exelon’s Strategy and Outlook for 2018 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 in long-term, contracted assets 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 meter

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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. Exelon's Board of Directors has approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March 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 of the Exelon 2017 Form 10-K for additional information regarding market and financial factors.

Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, which was fully realized in 2018. Approximately 75% of the savings were related to Generation, with the remaining amount related to the Utility Registrants. In November 2017, Exelon announced a commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. In November 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. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, 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 PHI merger provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $28 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $11 billion by the end of 2022. 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.

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immaterial. See Note 3 — ~~Regulatory Matters~~Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements ~~Exelon 2017 Form 10-K~~ for additional ~~information~~information.

Three Mile Island. On May 30, 2017, Generation announced it will permanently cease generation operations at TMI on ~~the Smart Meter and Smart Grid Initiatives 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 asor about September 30, 2019. 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.~~

~~Liquidity Considerations~~

~~Each~~result of the ~~Registrants annually evaluates its financing plan, dividend practices~~previous decision to early retire TMI, Exelon and ~~credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs~~Generation recorded a $75 million and $71 million incremental pre-tax net charge for the three and six months ended June 30, 2019 primarily due to ~~fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum~~accelerated depreciation of ~~financing alternatives beyond~~ the ~~core financing options can be used to meet its needs and fund growth including monetizing~~plant assets, partially offset by a benefit associated with the remeasurement of the TMI ARO in the ~~portfolio via project financing, asset sales,~~first quarter of 2019. For the full year ended December 31, 2019, Exelon and Generation estimate approximately $155 million of incremental pre-tax net non-cash charges associated with the ~~use~~early retirement of ~~other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows~~TMI, primarily due to ~~be sufficient to meet operating expenses, financing costs and capital expenditure requirements.~~

Exelon Corporate, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion.

~~For additional information regarding the Registrants' liquidity for the nine months ended September 30, 2018, see Liquidity and Capital Resources discussion below.~~

~~Project Financing~~

Generation utilizes individual project financings as a means to finance the construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project are paid back from the cash generated by the newly constructed asset once operational. 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 repaymentaccelerated depreciation of the ~~associated debt or other project-related borrowings earlier than the stated maturity dates.~~ plant assets.

Salem. 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 satisfy2017, PSEG announced that its ~~associated debt or other borrowings earlier than otherwise anticipated~~New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest, were showing increased signs of economic distress, which could lead to ~~impairments~~an early retirement. PSEG is the operator of Salem and also has the decision making authority to retire Salem. 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. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Assuming the continued effectiveness of the New Jersey ZEC program, Generation no longer considers Salem to be at heightened risk for early retirement.

Dresden, Byron and Braidwood. Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois 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. The May 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 of Byron and Braidwood. 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 6 — Regulatory Matters, Note 8 — Early Plant Retirements and Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

Pacific Gas & Electric Bankruptcy

Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As of June 30, 2019, Generation had approximately $740 million and $500 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. PG&E’s bankruptcy created an event of default for Antelope 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 ~~a higher~~be classified as current as of June 30, 2019.

In the first quarter of 2019, Generation assessed and determined that Antelope Valley’s long-lived assets were not impaired. Significant changes in assumptions such as the likelihood of ~~disposing~~the PPA being rejected as part of the ~~respective project-specific~~bankruptcy proceedings could potentially result in future impairments of Antelope Valley's net long-lived assets, ~~significantly before~~which could be material. Generation is monitoring the ~~end~~bankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of ~~their useful lives.~~ the net long-lived assets of Antelope Valley may not be recoverable.

See Note 7 — Impairment of Long-Lived Assets and Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on ~~nonrecourse debt.~~

the PG&E bankruptcy.

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Other Key Business Drivers and Management Strategies

~~Power Markets~~

~~Price~~The following discussion of ~~Fuels~~

~~The use~~other key business driver and management strategies includes current developments of previously disclosed matters and new ~~technologies to recover natural gas from shale deposits is increasing natural gas supply~~issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ~~reserves, which places downward pressure on natural gas prices~~ITEM 7. Management's Discussion and ~~therefore, on wholesale~~Analysis of Financial Condition 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~~

~~On August 23, 2017, the DOE staff released its report on the reliability~~Results of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September 28, 2017, the DOE 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 regulationOperations - Other Key Business Drivers and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On January 8, 2018, FERC issued an order terminating the rulemaking docket that it initiated to address the proposed ruleManagement Strategies in the ~~DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue~~Registrants' combined 2018 Form 10-K and ~~that it proposed a remedy that did not appear to be just, reasonable~~Note 16 - Commitments and ~~nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new proceeding to consider resiliency challenges~~Contingencies to the ~~bulk power system and evaluate whether~~Consolidated Financial Statements in this report for additional FERC 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 commentsinformation on May 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.various environmental matters.

Power Markets

Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs

PJM and NYISO capacity markets include a ~~Minimum Offer Price Rule (MOPR)~~MOPR that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.

On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New

Jersey ZEC, New York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute ~~that is distinct from the energy~~ and ~~capacity sold in the FERC-jurisdictional markets, and therefore,~~ are no different than other renewable support ~~programs like the PTC and RPS~~ programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, ~~(Quad Cities, Ginna, Fitzpatrick and Nine Mile Point),~~ an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions, ~~such that these facilities would have~~resulting in an increased risk of these facilities not ~~clearing in future capacity auctions and thus no longer~~ receiving capacity revenues ~~during the respective ZEC programs. Any mitigation of these generating resources~~in future auctions, which could have a material effect on Exelon’s

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and Generation’s future cash flows and results of operations. ~~The same risk would also exist for the Salem facility if Salem is selected as an eligible facility under the NJ ZEC program.~~

Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).

In June 2018, FERC ~~issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also~~ addressed one of the MOPR complaints involving PJM and concluded ~~based on that complaint and PJM’s filing~~ that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in ~~PJM regardless of the intent motivating the support.~~PJM. FERC suggested that modifying two elements of PJM’s existing tariff, as follows could produce a just and reasonable ~~replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an~~replacement.

An expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression. ~~Second, FERC preliminarily found that a~~

A modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism.

FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to ~~develop and~~ file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR ~~mechanism (as suggested by FERC) and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles.~~mechanism. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. On April 10, 2019, PJM notified FERC of its intent to proceed with the next capacity auction in August 2019 under the existing market rules and asked FERC to clarify that it would not require PJM to re-run the auction in the event FERC alters those market rules in its decision on the MOPR complaint. On July 25, 2019, FERC issued an order denying PJM’s request to clarify that any alteration of PJM’s existing market rules would operate prospectively and, therefore, directed PJM to not conduct the capacity auction in August 2019. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.

Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps

On February 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 asks FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.

Section 232 Uranium Petition

On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962, ~~(as amended)~~as amended, (the Act) from imports of uranium products, alleging that these imports threaten national security (the Petition). The ~~Trade Expansion~~relief requested would have required U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines for the next 10 years or more. The Act ~~of 1962 (the Act)~~ was promulgated by Congress 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 the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.

On July 18, 2018, the Secretary announced that the DOC ~~has~~had initiated an investigation in response to the petition. The Secretary ~~has 270 days to prepare and submit~~submitted a report to President Trump ~~who then~~on April 14, 2019 that has not been made public. On July 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 of the 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 a United States Nuclear Fuel Working Group (Working Group) be established to develop recommendations for reviving and expanding domestic nuclear fuel production with a mandate to submit a report back to him within 90 ~~days~~days. The Working Group is to ~~act on~~be co-chaired by the ~~Secretary's recommendations.~~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 the Working Group’s efforts. Exelon and Generation cannot currently predict the outcome of ~~this investigation. The relief sought by~~ the ~~petitioners would require U.S. nuclear reactors~~

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to purchase at least 25% of their uranium needs from domestic mines over the next 10 years, although the DOC will make an independent determination regarding an appropriate remedy should it find that imports impair national security. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a material, unfavorable impact on Exelon’sWorking Group report and ~~Generation’s results of operations, cash flows and financial positions.~~subsequent actions.

~~Potential DOE Order Pursuant to Defense Production Act and Federal Power Act~~

The DOE is considering an Order directing ISOs, for 24 months, to purchase electric energy or generation capacity from a designated list of coal and nuclear generation facilities. Based on a draft memorandum, the Order would be pursuant to DOE's authorities under the Defense Production Act and Federal Power Act, and would forestall any further actions towards retiring, decommissioning, or deactivating coal and nuclear facilities during the term of the Order. The Order would emphasize the importance of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The DOE recognizes that the underlying economic and regulatory issues are complex and will take time resolve. The Order's 24-month duration would enable DOE to conduct additional analyses to gain a detailed understanding of location-specific vulnerabilities in U.S. energy delivery systems, while preserving certain generation facilities. 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.

~~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 by 0.5%, 1.7%, 0.7%, 0.2%, 1.3% and 4.3% respectively, in 2018 compared to 2017.

~~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.

~~Strategic Policy Alignment~~

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 declared first quarter 2018 dividends of $0.345 per share on Exelon's common stock. The first quarter 2018 dividend was paid on March 9, 2018. The dividend increased from the fourth quarter 2017 amount to reflect the Board's decision to raise Exelon's dividend 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.

~~Exelon's board of directors declared second quarter 2018 dividends of $0.345 per share on Exelon's common stock and was paid on June 8, 2018.~~

~~Exelon's board of directors declared third quarter 2018 dividends of $0.345 per share on Exelon's common stock and was paid on September 10, 2018.~~

~~Table of Contents~~

~~Exelon's board of directors declared fourth quarter 2018 dividends of $0.345 per share on Exelon's common stock and is payable on December 10, 2018.~~

~~All future quarterly dividends require approval by Exelon's Board of Directors.~~

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. Generation has hedges in place that significantly mitigate this risk for 2018 and 2019. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of ~~September~~June 30, ~~2018,~~2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is ~~98%-101%~~92%-95%, ~~82%-85%~~70%-73% and ~~48%-51%~~40%-43% for ~~2018,~~ 2019, 2020, and ~~2020~~2021 respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price ~~risk in subsequent years as well.~~risk.

Generation procures ~~oil and~~ natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel isassemblies 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 ~~coal, oil and natural gas~~ are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately ~~59%~~62% of Generation’s uranium concentrate requirements from ~~2018~~2019 through ~~2022~~2023 are supplied by three producers. 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~~financial statements.

See Note 10 — Derivative Financial Instruments of ~~operations, cash flows~~the Combined Notes to Consolidated Financial Statements and ~~financial positions.~~Item 3. Quantitative and Qualitative Disclosures about Market Risk for additional information.

The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.

Environmental Legislative and Regulatory Developments

Exelon was actively involved in the Obama 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.

~~Table of Contents~~

Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama 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 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 certain existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings and withdrew all technical support documents supporting the calculation. Other regulations that are under review include the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the Coal Combustion Residuals rule. 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).~~ On December 16, 2011, the EPA 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. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two-year extension in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. 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 the D.C. Circuit Court as an intervenor in support of the rule.

Clean Power Plan.On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean 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 the EPA. ~~On October 10, 2017,~~In June 2019, EPA issued a ~~proposed~~final rule that repealed the CPP, and finalized the Affordable Clean Energy (ACE) rule to ~~repeal~~replace the CPP ~~in its entirety,~~with less stringent emissions guidelines based on ~~a proposed change in~~heat rate improvement measures that could be achieved within the ~~Agency’s legal interpretation~~fence line of ~~Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for~~ existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. The EPA has also issued an advance notice of proposed rulemaking to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.

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~~2015 Ozone National Ambient Air Quality Standards (NAAQS).~~ On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. Concurrent with its review, the Agency issued several rounds of final ozone designations for the 2015 ozone NAAQS in December 2017 and April 2018. On August 1, 2018, EPA filed a status report to the Court that indicated Agency does not intend to revise or repeal the 2015 ozone standard at this time. Subsequently the Court ordered the case reactivated.

Primary SO2 National Ambient Air Quality Standards (NAAQS). ~~On June 8, 2018,~~EPA took final action on April 17, 2019 to retain the ~~EPA proposed to maintain~~current primary SO2 standard without revision, leaving the ~~primary NAAQS for sulfur dioxide (SO2) at the same level and averaging time as was finalized by EPA~~standard established in ~~its~~ 2010 ~~SO2 NAAQS update. The schedule for completing this review is established by a consent decree, which sets January 28, 2019 as the deadline for signature on a final decision notice.~~

~~Climate Change.~~ Exelon supports comprehensive climate change legislation or regulation which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In June 2018, Exelon joined the Climate Leadership Council, which advocates for a revenue neutral carbon tax and dividend program. In the absence of Federal legislation, the EPA has been reviewing 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 the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1. BUSINESS, "Air Quality" of the Exelon 2017 Form 10-K for additional information.

~~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 are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic Unit 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities, and Salem. See ITEM 1. BUSINESS, "Water Quality" of the Exelon 2017 Form 10-K for additional information.

~~Solid and Hazardous Waste~~

In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classified CCR as non-hazardous waste under RCRA, and CCR continued to be regulated by most states subject to coordination with the federal regulations. In July 2018, the EPA issued a final rule amending the 2015 rule that provides more compliance flexibility to the states and owners and operators of coal ash disposal sites. Generation currently does not own or operate any such sites subject to the CCR rule. Generation previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the CCR rule 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 CCR rule 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.effect.

See Note 1716 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters, including the impact of environmental regulation.

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Other Legislative and Regulatory Developments

~~Delaware Distribution System Investment Charge~~Illinois Clean Energy Progress Act

On ~~June~~March 14, ~~2018,~~2019, the ~~Governor~~Clean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois’ clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of ~~Delaware signed~~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 in Illinois, or from new ~~Distribution System Investment Charge (DSIC) legislation, which~~clean energy resources, (2) it establishes a ~~system improvement charge that provides a mechanism to recover infrastructure investments, allowing for gradual rate increases and limiting frequency~~goal of ~~distribution base rate cases. DPL expects to make its first filing in Delaware~~achieving 100% carbon-free power in the ~~fourth quarter of 2018, with the new charge effective~~ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the ~~first quarter of 2019. While this~~state’s competitive retail electricity and natural gas markets, including Generation’s retail customers. Energy legislation ~~is expected to support needed infrastructure investment~~has also been proposed by other stakeholders, including renewable resource developers, environmental advocates, and ~~allow for more timely recovery of those investments, Exelon, PHI and DPL cannot predict the potential financial impact on Exelon, PHI or DPL.~~

~~Pennsylvania Alternative Ratemaking~~

On June 28, 2018, the Governor of Pennsylvania signed new legislation, which authorized the PAPUC to review and approve utility-proposed alternative rate mechanisms, including options such as decoupling mechanisms, formula rates, multi-year rate plans, and performance based rates.coal-fueled generators. Exelon and ~~PECO~~Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or ~~PECO.~~Generation.

~~Employees~~Keep Powering Pennsylvania Act

On March 11, 2019, the Keep Powering Pennsylvania Act was introduced in the Pennsylvania General Assembly to amend the Alternative Energy Portfolio Standards Act of 2004. The proposed legislation recognizes the value that all zero-emission electric generation resources provide to Pennsylvania by adding nuclear plants and certain other renewable generation resources (Tier III resources) to the zero-emission electric generation resources that currently receive alternative energy credits in Pennsylvania. Further, the proposed legislation would allow for these Tier III resources to continue to receive capacity payments at the same level as the PJM capacity auction clearing price. In ~~January 2017, an election was held~~order to initially qualify as a Tier III resource, a resource must make a commitment to operate for at ~~BGE which resulted in union representation~~least six years. The price of the alternative energy credits for ~~approximately 1,394 employees. BGE~~Tier III resources is tied to the value of existing Tier I resources, with a price cap. Regulated utilities, including PECO, would be required to purchase alternative energy credits for all retail customers and ~~IBEW Local 410~~allowed to recover those costs from customers. Exelon and Generation are ~~negotiating an initial agreement which could result in some modifications to wages, hours~~working with legislators and ~~other terms~~stakeholders and ~~conditions of employment. Negotiations have been productive and continue. No agreement has been finalized to date and management~~ cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.

Nuclear Powers Act of ~~such negotiations. Negotiations that began~~2019

On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United 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 ~~2017~~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 ~~a first collective bargaining agreement~~the credit, the plant must be currently operational and must have applied for an operating license renewal before 2026. Exelon and Generation are working with ~~a small unit of employees represented by Local 501 of Operating Engineers at Exelon’s Hyperion Solutions facility are complete~~legislators and stakeholders and cannot predict the ~~new CBA will expire in 2021. During 2017, Generation finalized~~outcome or the potential financial impact, if any, on Exelon or Generation.

Employees

In April 2019, the CBAs with ~~the Security Officer unions~~IBEW Local 15 covering employees at ~~LaSalle, Limerick~~BSC, ComEd and ~~Quad Cities, which all will~~Generation, were extended through 2024. The CBA between Pepco and IBEW Local 1900 was scheduled to expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two CBAs at Fitzpatrick into one CBA covering both craft and security employees, which will expire in 2023. Generation also successfully finalized the CBA with the IBEWon May 26, 2019, but has been extended to September 7, 2019. On June 23, 2019, BGE’s union at TMI, which will expire in 2022. During 2018, Generation finalized its CBA with the Security Officer’s union at Braidwood, which will expire in 2021. Additionally, negotiations are currently underwaycontract for the ~~two ACE Local 210 contracts,~~1,400 employees within local 410 was ratified. BGE is now in the process of implementing its terms, which ~~expire~~do not have a material impact on October 15, 2018 and December 9, 2018. Both sides are bargaining in good faith and we anticipate a mutually acceptable outcome from these negotiations. As previously reported, there was an organizing effort over approximately 18 ACE control room System Operators. While an election was held with an outcome favorable to Local 210, collective bargaining over this small segment of employees will not commence until the issue of whether the System Operators are NLRA statutory supervisors is determined, and that matter is currently before the NLRB. BGE's financial statements.

Critical Accounting Policies and Estimates

~~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~~

~~Table of Contents~~

~~Contracts with Customers, Derivative and Alternative Revenue Program (ARP) guidance to recognize revenue as discussed in more detail below.~~

~~Revenue from Contracts with Customers~~

Under the Revenue from Contracts with Customers guidance, 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 normal purchases and normal sales (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 5 — Accounts Receivable of the Exelon 2017 Form 10-K for additional information on unbilled revenue.~~

See Note 1 — Significant Accounting Policies and Note 5 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information on the impacts of the new revenue accounting standard effective for annual reporting periods beginning on or after December 15, 2017.

~~Derivative Revenues~~

The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.

~~Alternative Revenue Program Revenues~~

Certain of the Utility Registrants’ ratemaking mechanisms qualify as Alternative Revenue Programs (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

~~Table of Contents~~

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 and FERC 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 by FERC 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 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~

Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. At June 30, 2019, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2018. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATES in ~~Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's combined 2017~~the Registrants' 2018 Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, goodwill, purchase accounting, unamortized energy contract assets and liabilities, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies, revenue recognition and allowance for uncollectible accounts. At September 30, 2018, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2017.further information.

Results of Operations by Registrant

~~Net Income Attributable~~The Registrants' Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to ~~Common Shareholders~~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 ~~Registrant~~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.

146

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30,
Favorable
(Unfavorable)
Variance
2018 2017 2018 2017
Exelon $ 733
$ 823
$ (90 ) $ 1,858
$ 1,907
$ (49 )
Generation 234
304
(70 ) 547
487
60
ComEd 193
189
4
523
447
76
PECO 126
112
14
336
327
9
BGE 63
62
1
242
231
11
PHI 187
153
34
336
359
(23 )
Pepco 89
87
2
174
188
(14 )
DPL 33
31
2
90
107
(17 )
ACE 61
41
20
76
77
(1 )

~~Table of Contents~~

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s ~~2017~~2018 Form 10-K and (b) Notes 6 — Regulatory Matters and 1716 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

Item 1A. Risk Factors

Risks Related to Exelon

At ~~September~~June 30, ~~2018,~~2019, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined ~~2017~~2018 Form 10-K in ITEM 1A. RISK FACTORS.

Item 4. Mine Safety Disclosures

All Registrants

Not applicable to the Registrants.

~~Table~~Item 5. Other Information

Exelon and ComEd—Subpoena

Exelon and ComEd received a grand jury subpoena from the U.S. Attorney’s Office for the Northern District of ~~Contents~~

Illinois requiring production of information concerning their lobbying activities in the State of Illinois. Exelon and ComEd have pledged to cooperate fully and are cooperating fully with the U.S. Attorney’s Office in expeditiously providing the requested information.

Item 6. Exhibits

Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the Commission upon request.



Exhibit No.	Description
~~3.1~~4.1	~~Amended~~Atlantic City Electric Company Indenture Supplemental, dated as of May 2, 2019, to the Mortgage and ~~Restated Articles~~Deed of ~~Incorporation of Exelon Corporation~~Trust, dated January 15, 1937 (File No. ~~001-16169,~~001-03559, Form 8-K dated ~~July 27, 2018,~~May 21, 2019, Exhibit ~~3.1)~~4.3)

~~3.2~~4.2	~~Amended~~Potomac Electric Power Company Supplemental Indenture, dated as of May 2, 2019, with respect to the Mortgage and ~~Restated Bylaws~~Deed of ~~Exelon Corporation~~Trust, dated July 1, 1936 (File No. ~~001-16169,~~001-01072, Form 8-K dated ~~July 27, 2018,~~June 13, 2019, Exhibit ~~3.2)~~4.2)

~~4.1~~4.3	~~Supplemental Indenture~~Exempt Facilities Loan Agreement dated as of ~~July 26, 2018 from Commonwealth Edison~~June 1, 2019 between the Maryland Economic Development Corporation and Potomac Electric Power Company ~~to BNY Mellon Trust Company of Illinois, as trustee, and D. G. Donovan, as co-trustee~~ (File No. ~~001-01839,~~001-01072, Form 8-K dated ~~August 14, 2018,~~June 27, 2019, Exhibit 4.1)

~~4.2~~	~~Supplemental Indenture dated as of September 1, 2018 from PECO Energy Company to U.S. Bank National Association, as trustee (File No. 000-16844, Form 8-K dated September 11, 2018, Exhibit 4.1)~~

~~4.3~~	~~Supplemental Indenture dated as of October 9, 2018 from Atlantic City Electric Company to The Bank of New York Mellon, as trustee (File No. 001-03559, Form 8-K dated October 16, 2018, Exhibit 4.1)~~

101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH	XBRL Taxonomy Extension Schema Document.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB	XBRL Taxonomy Extension ~~Labels~~Label Linkbase Document.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended ~~September~~June 30, ~~2018~~2019 filed by the following officers for the following companies:



31-1	— Filed by Christopher M. Crane for Exelon Corporation

31-2	— Filed by Joseph Nigro for Exelon Corporation

31-3	— Filed by Kenneth W. Cornew for Exelon Generation Company, LLC

31-4	— Filed by Bryan P. Wright for Exelon Generation Company, LLC

31-5	— Filed by Joseph Dominguez for Commonwealth Edison Company

31-6	— Filed by Jeanne M. Jones for Commonwealth Edison Company

31-7	— Filed by Michael A. Innocenzo for PECO Energy Company

31-8	— Filed by Robert J. Stefani for PECO Energy Company

31-9	— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company

31-10	— Filed by David M. Vahos for Baltimore Gas and Electric Company

31-11	— Filed by David M. Velazquez for Pepco Holdings LLC

31-12	— Filed by Phillip S. Barnett for Pepco Holdings LLC

31-13	— Filed by David M. Velazquez for Potomac Electric Power Company

31-14	— Filed by Phillip S. Barnett for Potomac Electric Power Company

31-15	— Filed by David M. Velazquez for Delmarva Power & Light Company

31-16	— Filed by Phillip S. Barnett for Delmarva Power & Light Company

31-17	— Filed by David M. Velazquez for Atlantic City Electric Company

31-18	— Filed by Phillip S. Barnett for Atlantic City Electric Company

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Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended ~~September~~June 30, ~~2018~~2019 filed by the following officers for the following companies:




32-1	— Filed by Christopher M. Crane for Exelon Corporation

32-2	— Filed by Joseph Nigro for Exelon Corporation

32-3	— Filed by Kenneth W. Cornew for Exelon Generation Company, LLC

32-4	— Filed by Bryan P. Wright for Exelon Generation Company, LLC

32-5	— Filed by Joseph Dominguez for Commonwealth Edison Company

32-6	— Filed by Jeanne M. Jones for Commonwealth Edison Company

32-7	— Filed by Michael A. Innocenzo for PECO Energy Company

32-8	— Filed by Robert J. Stefani for PECO Energy Company

32-9	— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company

32-10	— Filed by David M. Vahos for Baltimore Gas and Electric Company

32-11	— Filed by David M. Velazquez for Pepco Holdings LLC

32-12	— Filed by Phillip S. Barnett for Pepco Holdings LLC

32-13	— Filed by David M. Velazquez for Potomac Electric Power Company

32-14	— Filed by Phillip S. Barnett for Potomac Electric Power Company

32-15	— Filed by David M. Velazquez for Delmarva Power & Light Company

32-16	— Filed by Phillip S. Barnett for Delmarva Power & Light Company

32-17	— Filed by David M. Velazquez for Atlantic City Electric Company

32-18	— Filed by Phillip S. Barnett for Atlantic City Electric Company

~~Table of Contents~~

SIGNATURES