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•	Exelon reported GAAP Net Income of $1.94 per share and $3.97 per share for the fourth quarter and full year 2017, respectively, and Adjusted (non-GAAP) Operating Earnings of $0.55 per share and $2.60 per share for the fourth quarter and full year 2017, respectively.

•	Exelon introduces a 2018 Adjusted (non-GAAP) Operating Earnings guidance range of $2.90 - $3.20 per share, reflecting growth in Utilities, full year recognition of both Illinois and New York ZEC revenue and the impact of tax reform.

•	Exelon's Board of Directors increased the annual dividend growth rate to 5 percent from 2.5 percent, effective in the first quarter of 2018.

•	Exelon Utilities project capital expenditures of $21 billion over the next 4 years to improve service and benefit customers, supporting over 7 percent annual rate base growth.

•	Exelon Generation projects free cash flow before growth capex of $7.6 billion over the next 4 years, supporting Exelon's priorities of Utility reinvestment and debt reduction.

•	Quad Cities Units 1 & 2 and Clinton Unit 1 were winning bidders in Illinois ZEC procurement.

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•	Mark-to-market adjustments from economic hedging activities;

•	Unrealized gains and losses from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements;

•	Non-cash amortization of intangible assets, net related to commodity contracts recorded at the date of the acquisition of ConEdison Solutions in 2016 and FitzPatrick in 2017;

•	Certain costs incurred related to the PHI and FitzPatrick acquisitions;

•	Certain costs incurred related to plant retirements;

•	Certain costs incurred to achieve cost management program savings;

•	Other unusual items;

•	Generation's noncontrolling interest related to CENG exclusion items; and

•	One-time impacts of adopting new accounting standards.

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•

Dividend Policy Update: On Jan. 30, 2018, the Board of Directors of Exelon announced an updated dividend policy targeting 5 percent annual dividend growth for the period covering 2018 through 2020. Since the last dividend policy of 2.5 percent annual growth was implemented in 2016, Exelon’s business position has continued to strengthen. The company has generated more earnings from regulated utilities following the PHI acquisition, recognized greater stability for its generation fleet with the Illinois and New York ZEC programs, and continued to focus on cost management and prudent balance sheet oversight. As a result of the strengthened outlook on earnings, Exelon is sharing the financial success with its shareholders through this updated dividend policy.

•

Utility Capex and Rate Base Update: Exelon Utilities plan to invest nearly $21 billion of capital to ensure reliable, more resilient and more efficient transmission and distribution of electricity and gas for our customers. The increased capital investments and impacts of tax reform are expected to drive annual rate base growth of 7.4 percent through 2021, exceeding the 6.5 percent growth expectations for 2017-2020 projected a year ago.

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Generation and Free Cash Flow Outlook: Cumulatively from 2018 through 2021, Generation projects $7.6 billion of free cash flow before growth capex, which is $0.8 billion higher than the prior 4-year outlook from 2017 through 2020. This financial outlook accounts for the latest power price forwards, updated gross margins at Constellation, continued efforts to reduce O&M cost and capital expenditures, the planned closure of Three Mile Island and Oyster Creek, and the impact of tax reform.

•

Exelon Nuclear Plants Selected in Illinois ZEC Procurement Event: On Jan. 25, 2018, the ICC announced that Clinton Unit 1 and Quad Cities Units 1 & 2 were winning bidders through the Illinois Power Agency's ZEC procurement event, which entitles them to compensation for the sale of ZECs. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018, and will begin recognizing revenue. In addition to recognizing ZEC revenue generated in the first quarter of 2018, Generation will also recognize ZEC revenue retroactive to June 1, 2017, which will contribute approximately $0.11 to Adjusted (non-GAAP) Operating Earnings. The $0.11 contribution to Adjusted (non-GAAP) Operating Earnings is higher than the $0.09 originally expected in 2017 due to the lower tax rate in 2018 at Generation as a result of the Tax Cuts and Jobs Act (TCJA).

•

Early Retirement of Oyster Creek Nuclear Facility: On Feb. 2, 2018, Generation announced that it will permanently cease generation operations at Oyster Creek Generating Station (Oyster Creek) at the end of its current operating cycle in October 2018. In 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the State of New Jersey to avoid significant costs associated with the construction of cooling towers to meet the State’s then new environmental regulations. Since then, like other nuclear sites, Oyster Creek has continued to face rising operating costs amid a historically low wholesale power price environment. The decision to retire Oyster Creek in 2018 at the end of its current operating cycle involved consideration of several factors, including economics and operating efficiencies, and avoids a refueling outage scheduled for the fall of 2018 that would have required advanced purchasing of fuel fabrication and materials beginning in late February 2018. Because of the decision to retire Oyster Creek in 2018, Generation will recognize certain one-time charges in the first quarter of 2018 ranging from an estimated $25 million to $35 million (pre-tax) related to a materials and supplies inventory reserve adjustment, employee-related costs, and construction work-in-progress impairment, among other items. The

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DOE Notice of Proposed Rulemaking: On Aug. 23, 2017, the United States Department of Energy (DOE) released its report on the reliability 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 Sept. 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 regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On Jan. 8, 2018, the FERC issued an order terminating the rulemaking docket that was 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, the FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. Exelon has been and will continue to be an active participant in these proceedings, but cannot predict the final outcome or its potential impact, if any, on Exelon or Generation.

•

Corporate Tax Reform: On Dec. 22, 2017, President Trump signed into law the TCJA. The Registrants remeasured their existing deferred income tax balances as of Dec. 31, 2017, to reflect the decrease in the corporate income tax rate from 35 percent to 21 percent, which resulted in a material decrease to their net deferred income tax liability balances. At Generation, this reduction in net deferred income tax liabilities resulted in a one-time credit to income tax expense of approximately $1.9 billion. The Utility Registrants offset virtually all similar reductions, totaling $7.3 billion, with net regulatory liabilities (rather than through earnings), given that changes in income taxes are generally passed through customer rates. The amount and timing of potential refunds of the established net regulatory liabilities will be determined by the Utility Registrants’ respective rate regulators, subject to certain IRS "normalization" rules.

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EGTP Bankruptcy: On Nov. 7, 2017, EGTP and all of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result, Exelon and Generation deconsolidated EGTP’s net liabilities, which included the previously impaired assets and related debt, from their consolidated financial statements, resulting in a $213 million pre-tax gain. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP’s generating plants, the Handley Generating Station, for approximately $60 million, subject to a potential adjustment for fuel oil and assumption of certain liabilities. The acquisition was approved by the Bankruptcy Court in January 2018 and the transaction is expected to be completed in the first half of 2018.

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Proposed Remedy for West Lake Landfill: On Feb. 1, 2018, the Environmental Protection Agency (EPA) announced a proposed remediation plan for the West Lake Landfill Superfund Site in Bridgeton, Missouri, for which Generation is one of the potentially responsible parties (PRPs). The proposed remediation plan includes a partial excavation of the site and an enhanced landfill cover and will be open for public comment through March 22, 2018, with the expectation that a Record of Decision will be issued during the third quarter of 2018. Thereafter, the EPA will seek to enter into a Consent Decree with the PRPs to effectuate the remedy, which Generation currently expects will occur in late 2018 or early 2019. The estimated total cost to fully execute the EPA’s proposed remedy is approximately $340 million, including cost escalation on an undiscounted basis, which will be allocated among the final group of PRPs. Generation increased its previous liability to reflect management’s best estimate of Generation’s allocable share of the cost of the proposed remedy among the PRPs, which could materially change in the future. The aforementioned 2017 charge has been excluded from GAAP Net Income to arrive at Adjusted (non-GAAP) Operating Earnings.

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ComEd Electric Distribution Rate Case: On Dec. 6, 2017, the ICC issued its final order approving ComEd’s 2017 annual distribution formula rate update. The final order resulted in an increase to the revenue requirement of $96 million, reflecting an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation for 2016. The increase was set using an allowed return on rate base of 6.47 percent for the initial revenue requirement and 6.45 percent for the annual reconciliation (inclusive of an allowed ROE of 8.40 percent for 2017 less a reliability performance metric penalty of 6 basis points for the 2016 reconciliation). The rates took effect in January 2018.

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Pepco District of Columbia Electric Distribution Rate Case: On Dec. 19, 2017, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $66 million, reflecting a requested ROE of 10.1 percent. By mid-February, Pepco will update its current distribution rate case to reflect the TCJA impacts. Pepco expects a decision in the matter in the fourth quarter of 2018, but cannot predict how much of the requested increase the DCPSC will approve.

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Pepco Maryland Electric Distribution Rate Case: On Jan. 2, 2018, Pepco filed an application with the MDPSC to increase its annual electric distribution base rates by $41 million, reflecting a requested ROE of 10.1 percent. On Feb. 5, 2018, Pepco filed with the MDPSC an update to its current distribution rate case to reflect approximately $31 million in TCJA tax savings, thereby reducing the requested annual base rate increase to $11 million. Pepco expects a decision in the matter in the third quarter of 2018, but cannot predict how much of the requested increase the MDPSC will approve.

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DPL Maryland Electric Distribution Rate Case: On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $27 million, which was updated to $19 million on Nov. 16, 2017, reflecting a requested ROE of 10.1 percent. On Dec. 18, 2017, DPL, the MDPSC Staff and Maryland’s Office of People’s Counsel filed a settlement agreement with the MDPSC that would provide DPL a rate increase of $13 million, and a ROE of 9.5 percent solely for purposes of calculating AFUDC and regulatory asset carrying costs. By mid-February, DPL is planning to file with the MDPSC seeking approval to pass back to customers beginning in 2018 approximately $13 million in annual tax savings resulting from the enactment of the TCJA through a reduction in electric distribution rates. DPL expects a decision in the matter in the first quarter of 2018, but cannot predict whether the MDPSC will approve the settlement agreement as filed or how much of the requested increase will be approved.

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FERC Transmission-Related Regulatory Asset Order: On Nov. 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover certain transmission-related income tax regulatory assets. ComEd, Pepco, DPL and ACE have similar transmission-related income tax regulatory assets also requiring FERC approval separate from their transmission formula rate mechanisms. Pursuant to the FERC order, management of each company concluded that the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery was no longer probable of recovery; and recorded impairment charges to Income tax expense of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million at Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE, respectively. Nevertheless, each company believes there is sufficient basis to support full recovery of all existing transmission-related income tax regulatory assets, and intends to further pursue such full recovery with FERC.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 47,528 gigawatt-hours (GWhs) in the fourth quarter of 2017, compared with 44,834 GWhs in the fourth quarter of 2016. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 95.3 percent capacity factor for the fourth quarter of 2017, compared with 94.2 percent for the fourth quarter of 2016. Excluding Salem, the number of planned refueling outage days in the fourth quarter of 2017 totaled 60, compared with 71 in the fourth quarter of 2016. There were 18 non-refueling outage days in the fourth quarter of 2017, compared with 32 days in the fourth quarter of 2016.

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Fossil and Renewables Operations: The dispatch match rate for Generation’s gas and hydro fleet was 98.4 percent in the fourth quarter of 2017, compared with 99.7 percent in the fourth quarter of 2016. The lower performance in the quarter was primarily due to outages at gas units in Texas and Alabama. The reported performance includes the EGTP sites, which Exelon maintained and operated through the quarter, but does not include Wolf Hollow II or Colorado Bend II, the two new CCGT units that went into full commercial operation in the second quarter. Energy capture for the wind and solar fleet was 96.2 percent in the fourth quarter of 2017, compared with 95.7 percent in the fourth quarter of 2016.

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•	Financing Activities:

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On Nov. 28, 2017, ExGen Renewables IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million non-recourse senior secured term loan credit facility agreement scheduled to mature on Nov. 28, 2024. The net proceeds of $785 million, after the initial funding of $50 million for debt service and liquidity reserves as well as deductions for original discount and issuance costs, were distributed to Generation for general corporate purposes. The term loan bears interest at a variable rate equal to LIBOR plus 3.00 percent, subject to a 1.00 percent LIBOR floor. As of Dec. 31, 2017, $850 million was outstanding. In addition to the financing, ExGen Renewables IV entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32 percent to manage a portion of the interest rate exposure in connection with the financing.

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(a)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.

(b)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

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(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(b)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company beginning on March 24, 2016, the day after the merger was completed.

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(a)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company beginning on March 24, 2016, the day after the merger was completed.

(b)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(c)	Adjustment to exclude the impact of unrealized gains and losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

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(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(e)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions.

(f)	Adjustment to exclude charges to earnings related to the PHI 2017 impairment of the District of Columbia sponsorship intangible asset.

(g)

Adjustment to exclude in 2016, incremental accelerated depreciation and amortization expenses from June 2, 2016 through December 6, 2016 pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generation facilities, which decision was reversed in December 2016, partially offset by the reversal of certain one-time charges for materials & supplies inventory reserves and severance reserves upon Generation’s decision to continue operating the plants with the passage of the Illinois Zero Emission Standard, and in 2017, an adjustment to exclude accelerated depreciation and amortization expenses associated with Generation’s decision to early retire the Three Mile Island nuclear facility.

(h)	Adjustment to exclude severance and reorganization costs related to a cost management program.

(i)	Adjustment to exclude in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, the one-time non-cash impacts associated with the Tax Cuts and Jobs Act (including impacts on pension obligations).

(j)	Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(k)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(l)	Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition and a charge related to a 2012 CEG merger commitment.

(m)	Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(n)	Adjustment to exclude the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

(o)	Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

(p)	Adjustment to exclude the elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.

(q)	The effective tax rate related to GAAP Net Income for the three months ended December 31, 2017 includes the impact of the Tax Cuts and Jobs Act.

(r)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 40.8% and 38.8% for the three months ended December 31, 2017 and 2016, respectively.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(c)	Adjustment to exclude the impact of unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(e)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions.

(f)	Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(g)	Adjustment to exclude charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments of the ExGen Texas Power, LLC (EGTP) assets and PHI District of Columbia sponsorship intangible asset.

(h)

Adjustment to exclude in 2016, accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site, and in 2017, primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, construction work in progress impairments and charges for severance reserves associated with Generation’s decision to early retire the Three Mile Island nuclear facility.

(i)

Adjustment to exclude in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (including impacts on pension obligations), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

(j)	Adjustment to exclude severance and reorganization costs related to a cost management program.

(k)	Adjustment to exclude in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(l)	Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(m)	Adjustment to exclude benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation.

(n)	Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(o)	Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(p)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(q)	Adjustment to exclude the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

(r)	Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

(s)	Adjustment to exclude the elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.

(t)	The effective tax rate related to GAAP Net Income for the twelve months ended December 31, 2017 includes the impact of the Tax Cuts and Jobs Act.

(u)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 36.9% and 34.4% for the twelve months ended December 31, 2017 and 2016, respectively.

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(a)	PHI consolidated results include Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.

(b)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(c)	For BGE, Pepco and DPL Maryland and beginning in 2017 for ComEd, customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes.

(d)	For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, BGE and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

(1)	Reflects the impact of unrealized gains and losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)	Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(3)	Primarily reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions.

(4)	Represents costs incurred as part of the settlement orders approving the PHI acquisition and a charge related to a 2012 CEG merger commitment.

(5)	Primarily reflects charges to earnings related to the PHI 2017 impairment of the District of Columbia sponsorship intangible asset.

(6)

In 2016, primarily reflects incremental accelerated depreciation and amortization expenses from June 2, 2016 through December 6, 2016 pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generation facilities, which decision was reversed in December 2016, partially offset by the reversal of certain one-time charges for materials & supplies inventory reserves and severance reserves upon Generation’s decision to continue operating the plants with the passage of the Illinois Zero Emission Standard. In 2017, primarily reflects accelerated depreciation and amortization expenses associated with Generation’s decision to early retire the Three Mile Island nuclear facility.

(7)	Represents severance and reorganization costs related to a cost management program.

(8)	Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, the one-time non-cash impacts associated with the Tax Cuts and Jobs Act (including impacts on pension obligations contained within Other).

(9)	Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(10)	Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

(11)	Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.

(12)	Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(13)	Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(14)	Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

(15)

For ComEd, primarily reflects lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act, almost entirely offset by increased electric distribution and transmission formula rate revenues (due to increased capital investments and higher electric distribution ROE, which is due to an increase in treasury rates). For BGE and PHI, primarily reflects increased revenue as a result of rate increases.

(16)	Primarily reflects the acquisition of the FitzPatrick nuclear facility and increased nuclear output.

(17)	Primarily reflects a decrease in fuel prices, offset by increased nuclear output as a result of the FitzPatrick acquisition.

(18)	Primarily reflects increased capacity prices in the New England, Midwest and Mid-Atlantic regions.

(19)	Reflects the impact of the New York Clean Energy Standard.

(20)	Primarily reflects lower realized energy prices and the conclusion of the Ginna Reliability Support Services Agreement, partially offset by the addition of two combined-cycle gas turbines in Texas.

(21)	Primarily reflects decreased variable compensation costs across the operating companies, partially offset at Generation by increased costs related to the acquisition of the FitzPatrick nuclear facility.

(22)	Primarily reflects the impact of increased refueling outage costs given an increased scope of outage activities, despite decreased outage days excluding Salem.

(23)	Primarily reflects the unfavorable impact of lower pension and OPEB discount rates, partially offset by the favorable impact of lower health care claims experience.

(24)	For Generation, primarily reflects the impact of an increased NEIL insurance credit. For ComEd, primarily reflects the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For BGE, primarily reflects the favorable 2016 settlement of the Baltimore City conduit fee dispute and an increase in uncollectible accounts expense.

(25)	For Generation, reflects increased depreciation for the addition of two combined-cycle gas turbines in Texas, partially offset by the absence of depreciation related to EGTP assets. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.

(26)	For Generation, primarily reflects the favorable change in one-time tax adjustments. Additionally, primarily reflects 2017 impairments at ComEd, BGE, and PHI of certain transmission-related income tax regulatory assets.

(27)	Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG and the Renewables Joint Venture.

(28)	Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding as a result of the June 2017 common stock issuance.

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(a)

For the twelve months ended December 31, 2016, includes financial results for PHI beginning on March 24, 2016, the day after the merger was completed. Therefore, the results of operations from 2017 and 2016 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. PHI consolidated results include Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.

(b)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(c)	For BGE, Pepco and DPL Maryland and beginning in 2017 for ComEd, customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes.

(d)	For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, BGE and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

(1)	Reflects the impact of unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)	Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(3)	Primarily reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions, partially offset in 2016 at ComEd, and in 2017 at PHI, by the anticipated recovery of previously incurred PHI acquisition costs.

(4)	Represents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(5)	Primarily reflects charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments of the ExGen Texas Power, LLC (EGTP) assets and PHI District of Columbia sponsorship intangible asset.

(6)

In 2016, primarily reflects accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site. In 2017, primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, construction work in progress impairments and charges for severance reserves associated with Generation’s decision to early retire the Three Mile Island nuclear facility.

(7)

Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

(8)	Represents severance and reorganization costs related to a cost management program.

(9)	Represents in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(10)	Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(11)	Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

(12)	Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.

(13)	Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation.

(14)	Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(15)	Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(16)	Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(17)	Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

(18)

For ComEd, primarily reflects increased distribution and transmission formula rate revenues (due to increased capital investments and higher electric distribution ROE, which is due to an increase in treasury rates), partially offset by lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For BGE and PHI, primarily reflects increased revenue as a result of rate increases.

(19)	Primarily reflects the acquisition of the FitzPatrick nuclear facility.

(20)	Primarily reflects a decrease in fuel prices, partially offset by increased nuclear output as a result of the FitzPatrick acquisition.

(21)	Primarily reflects increased capacity prices in the New England region, partially offset by a decrease in January through May capacity prices in the Mid-Atlantic region.

(22)	Reflects the impact of the New York Clean Energy Standard.

(23)	Primarily reflects lower realized energy prices, the impacts of lower load volumes delivered due to mild weather in the third quarter 2017, the conclusion of the Ginna Reliability Support Services Agreement and the impact of declining natural gas prices on Generation’s natural gas portfolio, partially offset by the addition of two combined-cycle gas turbines in Texas.

(24)	For Generation, primarily reflects increased costs related to the acquisition of the FitzPatrick nuclear facility. Additionally, reflects decreased variable compensation costs across the operating companies.

(25)	Primarily reflects an increase in the number of nuclear outage days in 2017, excluding Salem.

(26)	Primarily reflects the unfavorable impact of lower pension and OPEB discount rates, partially offset by the favorable impact of lower health care claims experience.

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(27)

For Generation, primarily reflects costs related to the acquisition of FitzPatrick, partially offset by the impact of an increased NEIL insurance credit. For ComEd, primarily reflects the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For BGE, primarily reflects certain disallowances contained in 2016 rate case orders and decreased storm costs in the BGE service territory, partially offset by the favorable 2016 settlement of the Baltimore City conduit fee dispute.

(28)

For Generation, reflects increased depreciation for the addition of two combined-cycle gas turbines in Texas, offset by the absence of depreciation related to the EGTP assets. For BGE, primarily reflects increased amortization due to the 2016 initiation of cost recovery of the AMI programs. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.

(29)	For Generation, primarily reflects the impact of project in-service dates on the capitalization of interest. For Corporate, primarily reflects increased interest expense due to higher outstanding debt, as well as debt issuance costs related to the April 2017 remarketing of Junior Subordinated Notes due in 2024.

(30)	For Generation, primarily reflects the unfavorable change in one-time tax adjustments. For PECO, primarily reflects an increase in the repairs tax deduction. Additionally, primarily reflects 2016 favorable adjustments at ComEd and BGE and 2017 impairments at ComEd, BGE, and PHI of certain transmission-related income tax regulatory assets.

(31)	Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG and the Renewables Joint Venture.

(32)	For Generation, primarily reflects higher realized NDT fund gains, partially offset by increased real estate taxes as a result of the FitzPatrick acquisition.

(33)	Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding as a result of the June 2017 common stock issuance.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(c)	Adjustment to exclude the impact of unrealized gains and losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(e)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions.

(f)	Adjustment to exclude in 2016 a charge related to a 2012 CEG merger commitment, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG acquisition.

(g)	Adjustment to exclude charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments of the ExGen Texas Power, LLC assets.

(h)

Adjustment to exclude for the three months ended December 31, 2016, incremental accelerated depreciation and amortization expenses from June 2, 2016 through December 6, 2016 pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generation facilities, which decision was reversed in December 2016, partially offset by the reversal of certain one-time charges for materials & supplies inventory reserves and severance reserves upon Generation’s decision to continue operating the plants with the passage of the Illinois Zero Emission Standard; and for the twelve months ended December 31, 2016, accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site. Additionally, reflects an adjustment to exclude in 2017 accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, construction work in progress impairments and charges for severance reserves associated with Generation’s decision to early retire the Three Mile Island nuclear facility.

(i)

Adjustment to exclude in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act, a change in the Illinois statutory tax rate and changes in forecasted apportionment.

(j)	Adjustment to exclude severance and reorganization costs related to a cost management program.

(k)	Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(l)	Adjustment to exclude benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation.

(m)	Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(n)	Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(o)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(p)	Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

(q)	Adjustment to exclude the elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.

(r)	Adjustment to exclude the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act and a change in the Illinois statutory tax rate.

(c)	Adjustment to exclude in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon's like-kind exchange tax position, and in 2017, adjustments to income tax and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

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(d)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition, partially offset in 2016 at ComEd by the anticipated recovery of previously incurred PHI acquisition costs.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition.

(c)	Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act.

(d)	Adjustment to exclude reorganization costs related to a cost management program.

(e)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition.

(c)	Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act.

(d)	Adjustment to exclude reorganization costs related to a cost management program.

(e)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)

For the twelve months ended December 31, 2016, includes financial results for PHI beginning on March 24, 2016, the day after the merger was completed. Therefore, the results of operations from 2017 and 2016 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. PHI consolidated results include Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company.

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(c)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition, partially offset in 2017 by the anticipated recovery of previously incurred PHI acquisition costs.

(d)	Adjustment to exclude in 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2016 PHI acquisition.

(e)	Adjustment to exclude the impairment of the District of Columbia sponsorship intangible asset.

(f)	Adjustment to exclude to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act.

(g)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

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(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(b)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

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(c)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(d)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition.

(e)	Adjustment to exclude in 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2016 PHI acquisition.

(f)

Adjustment to exclude in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (including impacts on pension obligations), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

(g)	Adjustment to exclude in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(h)	Adjustment to exclude costs related to impairments at Corporate.

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(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)	Other Power Regions includes, South, West and Canada.

(c)	Includes affiliate sales to PECO, BGE, Pepco, DPL and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(d)	Outage days exclude Salem.

(e)	Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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(a)	Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).

(b)	Includes affiliate sales to PECO, BGE, Pepco, DPL and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(c)	Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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(a)	Reflects delivery volumes and revenues from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission.

(b)	Other revenue primarily includes transmission revenue from PJM. Other revenue includes rental revenues, revenues related to late payment charges, revenues from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.

(c)	Includes operating revenues from affiliates totaling $3 million and $3 million for the three months ended December 31, 2017 and 2016, respectively, and $15 million and $15 million for the twelve months ended December 31, 2017 and 2016, respectively.

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(a)	Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

(d)

Total electric revenue includes operating revenues from affiliates totaling $2 million for both three months ended December 31, 2017 and 2016, respectively, and $6 million and $7 million for the twelve months ended December 31, 2017 and 2016, respectively.  Total natural gas revenue includes operating revenues from affiliates totaling less than $1 million for both three months ended December 31, 2017 and 2016 and $1 million for both twelve months ended December 31, 2017 and 2016.

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(a)	Reflects delivery volumes and revenue from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.

(b)	Other revenue primarily includes wholesale transmission revenue and late payment charges.

(c)	Includes operating revenues from affiliates totaling $1 million for both the three months ended December 31, 2017 and 2016 and $5 million and $7 million for the twelve months ended December 31, 2017 and 2016, respectively.

(d)	Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.

(e)	Transportation and other natural gas revenue includes off-system revenue of 1,152 mmcfs ($6 million) and 1,898 mmcfs ($8 million) for the three months ended December 31, 2017 and 2016, respectively, and 3,615 mmcfs ($21 million) and 5,977 mmcfs ($23 million) for the twelve months ended December 31, 2017 and 2016, respectively.

(f)	Includes operating revenues from affiliates totaling $4 million for both the three months ended December 31, 2017 and 2016 and $11 million and $14 million for the twelve months ended December 31, 2017 and 2016, respectively.

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(a)	Reflects delivery volumes and revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $2 million and $1 million for the three months ended December 31, 2017 and 2016, respectively, and $6 million and $5 million for the twelve months ended December 31, 2017 and 2016, respectively.

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(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. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $2 million and $1 million for the three months ended December 31, 2017 and 2016, respectively, and $8 million and $7 million for the twelve months ended December 31, 2017 and 2016, respectively.

(d)	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. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.

(e)	Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.

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(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. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended December 31, 2017 and 2016, respectively, and $2 million and $3 million for the twelve months ended December 31, 2017 and 2016, respectively.