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Regulatory Matters (All Registrants) | 12 Months Ended
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Dec. 31, 2018
Regulated Operations [Abstract] |
Regulatory Matters (All Registrants) | Regulatory Matters (All Registrants) The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants. Utility Regulatory Matters (Exelon and the Utility Registrants) Distribution Base Rate Case Proceedings The following tables show the completed and pending distribution base rate case proceedings in 2018. Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase (Decrease) |  | Approved Revenue Requirement Increase (Decrease) |  | Approved ROE | Approval Date | Rate Effective Date
ComEd - Illinois (Electric)(b) | April 16, 2018 | $ | (23 | ) | (a) | $ | (24 | ) | (a) | 8.69 | % | December 4, 2018 | January 1, 2019
PECO - Pennsylvania (Electric)(c) | March 29, 2018 | $ | 82 |  | (a) | $ | 25 |  | (a) | N/A | December 20, 2018 | January 1, 2019
BGE - Maryland (Natural Gas) | June 8, 2018 (amended August 24, 2018 and October 12, 2018) | $ | 61 |  |  | $ | 43 |  |  | 9.8 | % | January 4, 2019 | January 4, 2019
Pepco - Maryland (Electric) | January 2, 2018 (amended February 5, 2018) | $ | 3 |  | (a) | $ | (15 | ) | (a) | 9.5 | % | May 31, 2018 | June 1, 2018
Pepco - District of Columbia (Electric)(d) | December 19, 2017 (amended February 9, 2018) | $ | 66 |  |  | $ | (24 | ) | (a) | 9.525 | % | August 9, 2018 | August 13, 2018
DPL - Maryland (Electric)(e) | July 14, 2017 (amended November 16, 2017) | $ | 19 |  |  | $ | 13 |  |  | 9.5 | % | February 9, 2018 | February 9, 2018
DPL - Delaware (Electric) | August 17, 2017 (amended February 9, 2018) | $ | 12 |  | (a) | $ | (7 | ) | (a) | 9.7 | % | August 21, 2018 | March 17, 2018
DPL - Delaware (Natural Gas) | August 17, 2017 (amended February 9, 2018) | $ | 4 |  | (a) | $ | (4 | ) | (a) | 9.7 | % | November 8, 2018 | March 17, 2018
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(a) | Includes the annual ongoing TCJA tax savings further discussed below.
(b) | Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1 st, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation).
ComEd’s 2018 approved revenue requirement above reflects a decrease of $58 million for the initial year revenue requirement for 2018 and an increase of $34 million related to the annual reconciliation for 2017. The revenue requirement for 2018 and the annual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate. During the first quarter of 2018, ComEd revised its electric distribution formula rate to implement revenue decoupling provisions provided for under FEJA. As a result of this revision, ComEd’s electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer or numbers of customers. ComEd began reflecting the impacts of this change in its Operating revenues and electric distribution formula rate regulatory asset in the first quarter of 2017.
(c) | The PECO base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.
(d) | On September 7, 2018, Pepco submitted an updated filing for an increase of $4 million to the customer base rate credit established in connection with the merger between Exelon and PHI for residential customers, representing the TCJA benefits for the period January 1, 2018 through August 12, 2018.
(e) | The DPL Maryland base rate case proceeding was resolved through a settlement agreement, which did not specify an overall ROE. The settlement agreement included an ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs.
In the second quarter of 2018, DPL discovered a rate design issue in Maryland such that the current rates were not sufficient to collect the full amount of the $13 million revenue increase agreed to by the parties in the recent settlement. On September 5, 2018, the MDPSC approved DPL’s proposed revisions to resolve the rate design issue on a prospective basis, effective September 5, 2018. Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase |  | Requested ROE | Expected Approval Timing
ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |  | (a) | 10.1 | % | Third quarter of 2019(b)
Pepco - Maryland (Electric) | January 15, 2019 | $ | 30 |  |  | 10.3 | % | Third quarter of 2019
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(a) | Requested increase is before New Jersey sales and use tax and includes $40 million of higher depreciation expense related to its updated depreciation study and the annual ongoing TCJA tax savings further discussed below.
(b) | ACE plans to put interim rates in effect on or around May 21, 2019, subject to refund, as allowed by the regulation.
Transmission Formula Rates Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). For 2018, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:
Registrant | Initial Revenue Requirement (Decrease) Increase(b) | Annual Reconciliation Increase/(Decrease) | Total Revenue Requirement (Decrease) Increase |  | Allowed Return on Rate Base(d) | Allowed ROE(e)
ComEd(a) | $ | (44 | ) | $ | 18 |  | $ | (26 | ) |  | 8.32 | % | 11.50 | %
BGE(a) | 10 |  | 4 |  | 26 |  | (c) | 7.61 | % | 10.50 | %
Pepco | 6 |  | 2 |  | 8 |  |  | 7.82 | % | 10.50 | %
DPL | 14 |  | 13 |  | 27 |  |  | 7.29 | % | 10.50 | %
ACE(a) | 4 |  | (4 | ) | — |  |  | 8.02 | % | 10.50 | %
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(a) | The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted.
(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 below.
(c) | The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to 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%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, 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 RTO.
Pending Transmission Formula Rate (Exelon and PECO). 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 formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity 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. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve. On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, 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. Tax Cuts and Jobs Act The Utility Registrants have made filings with their state regulatory commissions to pass back tax savings related to TCJA to their distribution customers, which are detailed below. The tax savings include the benefit of lower federal income tax rates and the settlement of a portion of the deferred income tax regulatory liabilities established upon the enactment of the TCJA. The ongoing annual TCJA tax savings in the table below represent the annual savings for distribution customers reflected in the initial customers rates approved after the TCJA. Subsequent annual TCJA tax savings will be approved as part of the annual update to the electric distribution formula rate for ComEd or base rate case proceedings for PECO, BGE, Pepco, DPL and ACE.
| Ongoing TCJA Tax Savings | Stub Period Bill Credit from TCJA Tax Savings
Registrant/Jurisdiction | Amount | Approval Date | Rate Effective Date | Stub Period | Approval Date | Refund Amount/Period
ComEd - Illinois (Electric) | $ | 201 |  | January 18, 2018 | February 1, 2018 | Not applicable
PECO - Pennsylvania (Electric) | $ | 71 |  | December 20, 2018 | January 1, 2019 | January 1, 2018 - December 31, 2018 | December 20, 2018 | $67 / 2019 (majority in January)
PECO - Pennsylvania (Natural Gas) | $ | 4 |  | (a) | July 1, 2018 | Not applicable
BGE - Maryland (Electric) | $ | 72 |  | January 31, 2018 | February 1, 2018 | January 1, 2018 - January 31, 2018 | To be addressed in next electric distribution base rate case
BGE - Maryland (Natural Gas) | $ | 31 |  | January 31, 2018 | February 1, 2018 | January 1, 2018 - January 31, 2018 | January 4, 2019 | $2 / Q1 2019
Pepco - Maryland (Electric) | $ | 31 |  | May 31, 2018 | June 1, 2018 | January 1, 2018 - June 1, 2018 | May 31, 2018 | $10 / July 2018
Pepco - District of Columbia (Electric) | $ | 39 |  | August 9, 2018 | August 13, 2018 | January 1, 2018 - August 12, 2018 | September 7, 2018 | $20 / September 2018
DPL - Maryland (Electric) | $ | 14 |  | April 18, 2018 | April 20, 2018 | January 1, 2018 - March 31, 2018 | April 18, 2018 | $2 / June 2018
DPL - Delaware (Electric) | $ | 19 |  | August 21, 2018 | March 17, 2018 | February 1, 2018 - March 17, 2018 | August 21, 2018 | $3 / Q4 2018
DPL - Delaware (Natural Gas) | $ | 7 |  | November 8, 2018 | March 17, 2018 | February 1, 2018 - March 17, 2018 | November 8, 2018 | $1 / Q4 2018
ACE - New Jersey (Electric) | $ | 23 |  | August 29, 2018 | September 8, 2018 | January 1, 2018 - June 30, 2018 | August 29, 2018 | $6 / Q4 2018
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(a) | On May 17, 2018, the PAPUC issued an order directing Pennsylvania utility companies without an existing base rate case, including PECO’s gas distribution business, to start passing back the savings from January 1, 2018 onward through a negative surcharge mechanism to be effective on July 1, 2018. Pursuant to that order, PECO filed a negative surcharge mechanism and began on July 1, 2018, to return the estimated annual 2018 tax savings above to its natural gas distribution customers.
As discussed above, ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission formula rates currently do not provide for the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. On December 13, 2016 (as amended on March 13, 2017) and on February 23, 2018 (as amended on July 9, 2018), BGE and ComEd, Pepco, DPL and ACE, respectively, each filed with FERC to revise their transmission formula rate mechanisms to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets, including those established upon enactment of the TCJA. See discussion below for additional information regarding these filings. See Note 14 - Income Taxes for additional information on Corporate Tax Reform. Other State Regulatory Matters Illinois Regulatory Matters Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the return on equity that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1 st each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate. During 2018, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:
Filing Date | Requested Revenue Requirement Increase | Approved Revenue Requirement Increase |  | Approved ROE | Approval Date | Rate Effective Date
June 1, 2018 | $ | 39 |  | $ | 42 |  | (a) | 8.69 | % | December 4, 2018 | January 1, 2019
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(a) | ComEd’s 2018 approved revenue requirement above reflects an increase of $41 million for the initial year revenue requirement for 2018 and 2019 and an increase of $1 million related to the annual reconciliation for 2017. The revenue requirement for 2018 and 2019 and the annual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.
Maryland Regulatory Matters Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which acts as a proxy for retail suppliers’ costs. The Commission accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the SOS. The appeal currently resides with the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal. Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. See AMI programs in the Regulatory Assets and Liabilities section below for additional information. As part of the 2015 electric and natural gas distribution rate case filed on November 6, 2015, BGE sought recovery of its smart grid initiative costs, supported by evidence demonstrating that BGE had, in fact, implemented a cost-beneficial advanced metering system. On June 3, 2016, the MDPSC issued an order concluding that the smart grid initiative overall is cost beneficial to its customers. However, the June 3 rd order contained several cost disallowances and adjustments including disallowances of certain program and meter installation costs and denial of recovery of any return on unrecovered costs for non-AMI meters replaced under the program. BGE and the residential consumer advocate subsequently both filed a petition for rehearing of the June 3 rd order. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. As a combined result of the MDPSC orders in BGE's 2015 electric and natural gas distribution base rate case, BGE recorded a $52 million charge in June 2016 to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory assets and other long-lived assets and reclassified $56 million of legacy meter costs from Property, plant and equipment, net to Regulatory assets in Exelon's and BGE's Consolidated Balance Sheets. In BGE’s 2018 natural gas distribution base rate case, the MDPSC allowed BGE to recover the gas portion of the post-test year regulatory asset, including a return thereon, over three years. The electric portion of the same regulatory asset will be addressed in BGE’s next electric distribution base rate case. The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In 2013, legislation in Maryland was signed into law to establish a mechanism, separate from base rate proceedings, for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects incurred after June 1, 2013. The monthly surcharge and infrastructure replacement costs must be approved by the MDPSC and are subject to a cap and require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution base rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On December 1, 2017 (as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge will be effective in rates beginning in January 2019. The new five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million, with an associated revenue requirement of $200 million. District of Columbia Regulatory Matters District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). The District of Columbia government enacted on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. The $250 million of project costs funded by Pepco will earn a return and be recovered through a volumetric surcharge on the electric bill of Pepco's customers in the District of Columbia. The $250 million of project costs funded by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers through a volumetric distribution rider. The remaining costs up to $62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Ownership and responsibility for the operation and maintenance of assets funded by the District of Columbia will be transferred to Pepco for a nominal amount upon completion, and Pepco will not recover or earn a return on the cost of these assets. In accordance with the Infrastructure Improvement Financing Act, Pepco filed an application for approval of the first two-year plan in the DC PLUG initiative (the First Biennial Plan) on July 3, 2017. Pepco will then be required to make two additional applications. On November 9, 2017, the DCPSC issued an order approving the First Biennial Plan and the application for a financing order. Pursuant to that order, Pepco is obligated to pay $187.5 million to the District of Columbia over the six-year project term, of which it expects to pay $30 million in 2019. Pepco recorded an obligation and offsetting regulatory asset in November. Rates for the DC PLUG initiative went into effect on February 7, 2018. New Jersey Regulatory Matters ACE Infrastructure Investment Program Filing (Exelon, PHI and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s Infrastructure Investment Program (IIP) proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. ACE currently expects a decision in this matter in the second quarter of 2019 but cannot predict if the NJBPU will approve the application as filed. New Jersey Consolidated Tax Adjustment (Exelon, PHI and ACE). The Consolidated Tax Adjustment (CTA) is a ratemaking policy that requires utilities that are part of a consolidated tax group to share with customers the tax benefits that came from losses at unregulated affiliates through a reduction in rate base. After opening a generic proceeding to review the policy, in 2014, the NJBPU issued a decision which retained the CTA, but in a modified format that significantly reduced the impact of the CTA to ACE. On September 18, 2017, the Appellate Division of the Superior Court of New Jersey reversed the NJBPU’s decision in adopting the revised CTA policy and held that NJBPU’s actions related to the CTA constituted a rulemaking that should have been undertaken pursuant to the requirements of the Administrative Procedures Act. The Court did not address the merits of the CTA methodology itself. The NJBPU issued a proposed rule for comment, consistent with the requirements of the Administrative Procedures Act. On January 17, 2019, the NJBPU adopted the proposed CTA regulations, which do not have a material impact on ACE. The CTA regulations will be sent to the Office of Administrative Law for publication in the New Jersey Register, which is expected on or before March 4, 2019. New Jersey Clean Energy Legislation (Exelon and ACE). On May 23, 2018, the Governor of New Jersey signed new legislation, effective immediately, that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. The new legislation expands the state's renewable portfolio standard to require that 50% of electric generation sold be from renewable energy sources by 2030; modifies the New Jersey solar renewable energy portfolio standard to require that 5.1% of electric generation sold in New Jersey be from solar electric power by 2021; lowers the solar alternative compliance payment amount starting in 2019 and requires the NJBPU to adopt rules to replace the current solar renewable energy credit program; and requires the NJBPU to increase its offshore wind energy credit program to 3,500 MW. The new legislation further imposes an energy efficiency standard that each electric public utility will be required to reduce annual usage by 2% and provides for utilities to annually file for recovery of the costs of the programs, including the revenue impact of sales losses resulting from the programs. The NJBPU is required to initiate a study to determine the savings targets for each public utility, to adopt other rules regarding the programs, and to approve energy efficiency and peak demand reduction programs for each utility. The new legislation also requires the NJBPU to conduct an energy storage analysis including the potential costs and benefits and to initiate a proceeding to establish a goal of achieving 2,000 MW of energy storage by 2030; requires the utilities to conduct a study on voltage optimization on their distribution system; and requires the NJBPU to establish a community solar program to permit customers to participate in a solar project that is not located on the customer’s property which the NJBPU issued regulations on January 17, 2019. On the same day, the Governor of New Jersey also signed new legislation, effective immediately, that will establish a ZEC program providing 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. Electric distribution utilities in New Jersey, including ACE, will be authorized to collect from retail distribution customers through a non-bypassable charge all costs associated with the utility’s procurement of the ZECs. See Generation Regulatory Matters below for additional information. Other Federal Regulatory Matters Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. FERC’s rejection order focused on the lack of timeliness of BGE’s request to recover amounts that would have been previously amortized but indicated that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. Based on FERC’s 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. As a result, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE recorded the following charges to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017, reducing their associated transmission-related income tax regulatory assets. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula and, thus, are not impacted by BGE’s November 16, 2017 FERC order. See above for additional information regarding PECO's transmission formula rate filing.
| For the year ended December 31, 2017
Exelon | $ | 35 |
ComEd | 3 |
BGE | 5 |
PHI | 27 |
Pepco | 14 |
DPL | 6 |
ACE | 7 |
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s order, still seeking full recovery of its existing transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. On February 27, 2018 (and updated on March 26, 2018), BGE submitted a letter to FERC advising that the lower federal corporate income tax rate effective January 1, 2018 provided for in the TCJA will be reflected in BGE’s annual formula rate update effective June 1, 2018, but that the deferred income tax benefits will not be passed back to customers unless BGE’s formula rate is revised to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets. On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to facilitate passing back to customers ongoing annual TCJA tax savings and to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, again citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. The orders did not address the remittance of TCJA transmission-related income tax regulatory liabilities, but rather referenced FERC’s separate Notice of Inquiry of such amounts issued on March 15, 2018. On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted new filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. FERC issued deficiency letters requesting additional information on November 21, 2018 and January 28, 2019. ComEd, BGE, Pepco, DPL, and ACE responded to the November 21, 2018 deficiency letter on November 29, 2018 but cannot predict the outcome of these FERC proceedings. If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $76 million, $51 million, $15 million, $10 million, $3 million, $5 million and $2 million, respectively, as of December 31, 2018. On October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order, still seeking full recovery of their existing transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. ComEd, Pepco, DPL, and ACE cannot predict the outcome of this rehearing request. On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the Court of Appeals for the D.C. Circuit. PJM Transmission Rate Design (All Registrants). On June 15, 2016, several parties, including the Utility Registrants, filed a proposed settlement with FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. The settlement included provisions for monthly credits or charges related to the periods prior to January 1, 2016 that are expected to be refunded or recovered through PJM wholesale transmission rates through December 2025. On May 31, 2018, FERC issued an order approving the settlement and directed PJM to adjust wholesale transmission rates within 30 days. Pursuant to the order, similar charges for the period January 1, 2016 through June 30, 2018 will also be refunded or recovered through PJM wholesale transmission rates over the subsequent 12-month period. PJM commenced billing the refunds and charges associated with this settlement in August 2018. The Utility Registrants expect to refund or recover these settlement amounts through prospective electric distribution customer rates. On July 2, 2018, several parties filed petitions for rehearing or clarification. Pursuant to the FERC approval of the settlement and the expected refund or recovery of the associated amounts from electric distribution customers, in the second quarter of 2018 and as adjusted in the third quarter of 2018, the Utility Registrants recorded the following payables to/receivables from PJM and related regulatory assets/liabilities. Generation recorded a $41 million net payable to PJM and a pre-tax charge within Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
| PJM Receivable | PJM Payable | Regulatory Asset | Regulatory Liability
Exelon | $ | 220 |  | $ | 176 |  | $ | 136 |  | $ | 221 |
Generation(a) | — |  | 41 |  | — |  | — |
ComEd | 122 |  | — |  | — |  | 122 |
PECO | 85 |  | — |  | — |  | 85 |
BGE | — |  | 51 |  | 51 |  | — |
PHI | 13 |  | 84 |  | 85 |  | 14 |
Pepco | — |  | 84 |  | 84 |  | — |
DPL | 10 |  | — |  | — |  | 10 |
ACE | 3 |  | — |  | 1 |  | 4 |
__________
(a) | Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018.
Regulatory Assets and Liabilities Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs. The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of December 31, 2018 and December 31, 2017:
December 31, 2018 | Exelon |  | ComEd |  | PECO |  | BGE |  | PHI |  | Pepco |  | DPL |  | ACE
Regulatory assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Pension and other postretirement benefits | $ | 2,553 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Pension and other postretirement benefits - Merger related | 1,266 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Deferred income taxes | 414 |  |  | — |  |  | 404 |  |  | — |  |  | 10 |  |  | 10 |  |  | — |  |  | — |
AMI programs - Deployment Costs | 202 |  |  | — |  |  | — |  |  | 113 |  |  | 89 |  |  | 50 |  |  | 39 |  |  | — |
AMI programs - Legacy Meters | 328 |  |  | 136 |  |  | 24 |  |  | 48 |  |  | 120 |  |  | 90 |  |  | 30 |  |  | — |
AMI programs - Post-test year costs | 32 |  |  | — |  |  | — |  |  | 32 |  |  | — |  |  | — |  |  | — |  |  | — |
Electric distribution formula rate annual reconciliations | 158 |  |  | 158 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Electric distribution formula rate significant one-time events | 81 |  |  | 81 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Energy efficiency costs | 472 |  |  | 472 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Fair value of long-term debt | 702 |  |  | — |  |  | — |  |  | — |  |  | 569 |  |  | — |  |  | — |  |  | — |
Fair value of PHI's unamortized energy contracts | 561 |  |  | — |  |  | — |  |  | — |  |  | 561 |  |  | — |  |  | — |  |  | — |
Asset retirement obligations | 118 |  |  | 79 |  |  | 22 |  |  | 16 |  |  | 1 |  |  | 1 |  |  | — |  |  | — |
MGP remediation costs | 326 |  |  | 309 |  |  | 17 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Renewable energy | 249 |  |  | 249 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Electric Energy and Natural Gas Costs | 193 |  |  | — |  |  | 49 |  |  | 51 |  |  | 93 |  |  | 84 |  |  | — |  |  | 9 |
Transmission formula rate annual reconciliations | 41 |  |  | 6 |  |  | — |  |  | 4 |  |  | 31 |  |  | 10 |  |  | 14 |  |  | 7 |
Energy efficiency and demand response programs | 545 |  |  | — |  |  | 1 |  |  | 289 |  |  | 255 |  |  | 188 |  |  | 67 |  |  | — |
Merger integration costs | 42 |  |  | — |  |  | — |  |  | 3 |  |  | 39 |  |  | 18 |  |  | 11 |  |  | 10 |
Under-recovered revenue decoupling | 59 |  |  | — |  |  | — |  |  | 2 |  |  | 57 |  |  | 57 |  |  | — |  |  | — |
Securitized stranded costs | 50 |  |  | — |  |  | — |  |  | — |  |  | 50 |  |  | — |  |  | — |  |  | 50 |
Removal costs | 564 |  |  | — |  |  | — |  |  | — |  |  | 564 |  |  | 158 |  |  | 97 |  |  | 309 |
DC PLUG charge | 159 |  |  | — |  |  | — |  |  | — |  |  | 159 |  |  | 159 |  |  | — |  |  | — |
Deferred storm costs | 41 |  |  | — |  |  | — |  |  | — |  |  | 41 |  |  | 9 |  |  | 4 |  |  | 28 |
Other | 303 |  |  | 110 |  |  | 24 |  |  | 17 |  |  | 162 |  |  | 79 |  |  | 28 |  |  | 13 |
Total regulatory assets | 9,459 |  |  | 1,600 |  |  | 541 |  |  | 575 |  |  | 2,801 |  |  | 913 |  |  | 290 |  |  | 426 |
Less: current portion | 1,222 |  |  | 293 |  |  | 81 |  |  | 177 |  |  | 489 |  |  | 270 |  |  | 59 |  |  | 40 |
Total noncurrent regulatory assets | $ | 8,237 |  |  | $ | 1,307 |  |  | $ | 460 |  |  | $ | 398 |  |  | $ | 2,312 |  |  | $ | 643 |  |  | $ | 231 |  |  | $ | 386 |
December 31, 2018 | Exelon |  | ComEd |  | PECO |  | BGE |  | PHI |  | Pepco |  | DPL |  | ACE
Regulatory liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred income taxes | $ | 5,228 |  |  | $ | 2,394 |  |  | $ | — |  |  | $ | 1,132 |  |  | $ | 1,702 |  |  | $ | 798 |  |  | $ | 510 |  |  | $ | 394 |
Nuclear decommissioning | 2,606 |  |  | 2,217 |  |  | 389 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Removal costs | 1,547 |  |  | 1,368 |  |  | — |  |  | 52 |  |  | 127 |  |  | 20 |  |  | 107 |  |  | — |
Electric Energy and Natural Gas Costs | 294 |  |  | 137 |  |  | 132 |  |  | 6 |  |  | 19 |  |  | — |  |  | 18 |  |  | 1 |
Other | 528 |  |  | 227 |  |  | 75 |  |  | 79 |  |  | 100 |  |  | 11 |  |  | 30 |  |  | 25 |
Total regulatory liabilities | 10,203 |  |  | 6,343 |  |  | 596 |  |  | 1,269 |  |  | 1,948 |  |  | 829 |  |  | 665 |  |  | 420 |
Less: current portion | 644 |  |  | 293 |  |  | 175 |  |  | 77 |  |  | 84 |  |  | 7 |  |  | 59 |  |  | 18 |
Total noncurrent regulatory liabilities | $ | 9,559 |  |  | $ | 6,050 |  |  | $ | 421 |  |  | $ | 1,192 |  |  | $ | 1,864 |  |  | $ | 822 |  |  | $ | 606 |  |  | $ | 402 |
December 31, 2017 | Exelon |  | ComEd |  | PECO |  | BGE |  | PHI |  | Pepco |  | DPL |  | ACE
Regulatory assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Pension and other postretirement benefits | $ | 2,455 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Pension and other postretirement benefits - Merger related | 1,393 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Deferred income taxes | 306 |  |  | — |  |  | 297 |  |  | — |  |  | 9 |  |  | 9 |  |  | — |  |  | — |
AMI programs - Deployment costs | 385 |  |  | — |  |  | — |  |  | 129 |  |  | 101 |  |  | 58 |  |  | 43 |  |  | — |
AMI programs - Legacy meters | 223 |  |  | 155 |  |  | 36 |  |  | 53 |  |  | 134 |  |  | 100 |  |  | 34 |  |  | — |
AMI programs - Post-test year costs | 32 |  |  | — |  |  | — |  |  | 32 |  |  | — |  |  | — |  |  | — |  |  | — |
Electric distribution formula rate annual reconciliations | 186 |  |  | 186 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Electric distribution formula rate significant one-time events | 58 |  |  | 58 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Energy efficiency costs | 166 |  |  | 166 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Fair value of long-term debt | 758 |  |  | — |  |  | — |  |  | — |  |  | 619 |  |  | — |  |  | — |  |  | — |
Fair value of PHI's unamortized energy contracts | 750 |  |  | — |  |  | — |  |  | — |  |  | 750 |  |  | — |  |  | — |  |  | — |
Asset retirement obligations | 109 |  |  | 73 |  |  | 22 |  |  | 14 |  |  | — |  |  | — |  |  | — |  |  | — |
MGP remediation costs | 295 |  |  | 273 |  |  | 22 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Renewable energy | 258 |  |  | 256 |  |  | — |  |  | — |  |  | 2 |  |  | — |  |  | 1 |  |  | 1 |
Electric energy and natural gas costs | 47 |  |  | — |  |  | 1 |  |  | 16 |  |  | 30 |  |  | 8 |  |  | 7 |  |  | 15 |
Transmission formula rate annual reconciliations | 35 |  |  | 6 |  |  | — |  |  | 7 |  |  | 22 |  |  | 3 |  |  | 8 |  |  | 11 |
Energy efficiency and demand response programs | 596 |  |  | — |  |  | 1 |  |  | 285 |  |  | 310 |  |  | 229 |  |  | 81 |  |  | — |
Merger integration costs | 45 |  |  | — |  |  | — |  |  | 6 |  |  | 39 |  |  | 20 |  |  | 10 |  |  | 9 |
Under-recovered revenue decoupling | 55 |  |  | — |  |  | — |  |  | 14 |  |  | 41 |  |  | 38 |  |  | 3 |  |  | — |
Securitized stranded costs | 79 |  |  | — |  |  | — |  |  | — |  |  | 79 |  |  | — |  |  | — |  |  | 79 |
Removal costs | 529 |  |  | — |  |  | — |  |  | — |  |  | 529 |  |  | 150 |  |  | 93 |  |  | 286 |
DC PLUG charge | 190 |  |  | — |  |  | — |  |  | — |  |  | 190 |  |  | 190 |  |  | — |  |  | — |
Deferred storm costs | 27 |  |  | — |  |  | — |  |  | — |  |  | 27 |  |  | 7 |  |  | 5 |  |  | 15 |
Other | 311 |  |  | 106 |  |  | 31 |  |  | 15 |  |  | 165 |  |  | 79 |  |  | 29 |  |  | 14 |
Total regulatory assets | 9,288 |  |  | 1,279 |  |  | 410 |  |  | 571 |  |  | 3,047 |  |  | 891 |  |  | 314 |  |  | 430 |
Less: current portion | 1,267 |  |  | 225 |  |  | 29 |  |  | 174 |  |  | 554 |  |  | 213 |  |  | 69 |  |  | 71 |
Total noncurrent regulatory assets | $ | 8,021 |  |  | $ | 1,054 |  |  | $ | 381 |  |  | $ | 397 |  |  | $ | 2,493 |  |  | $ | 678 |  |  | $ | 245 |  |  | $ | 359 |
December 31, 2017 | Exelon |  | ComEd |  | PECO |  | BGE |  | PHI |  | Pepco |  | DPL |  | ACE
Regulatory liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred income taxes | $ | 5,241 |  |  | $ | 2,479 |  |  | $ | — |  |  | $ | 1,032 |  |  | $ | 1,730 |  |  | $ | 809 |  |  | $ | 510 |  |  | $ | 411 |
Nuclear decommissioning | 3,064 |  |  | 2,528 |  |  | 536 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Removal costs | 1,573 |  |  | 1,338 |  |  | — |  |  | 105 |  |  | 130 |  |  | 20 |  |  | 110 |  |  | — |
Electric Energy and Natural Gas Costs | 111 |  |  | 47 |  |  | 60 |  |  | — |  |  | 4 |  |  | — |  |  | 1 |  |  | 3 |
Other | 399 |  |  | 185 |  |  | 94 |  |  | 26 |  |  | 64 |  |  | 3 |  |  | 14 |  |  | 8 |
Total regulatory liabilities | 10,388 |  |  | 6,577 |  |  | 690 |  |  | 1,163 |  |  | 1,928 |  |  | 832 |  |  | 635 |  |  | 422 |
Less: current portion | 523 |  |  | 249 |  |  | 141 |  |  | 62 |  |  | 56 |  |  | 3 |  |  | 42 |  |  | 11 |
Total noncurrent regulatory liabilities | $ | 9,865 |  |  | $ | 6,328 |  |  | $ | 549 |  |  | $ | 1,101 |  |  | $ | 1,872 |  |  | $ | 829 |  |  | $ | 593 |  |  | $ | 411 |
Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return
Pension and Other Postretirement Benefits | Primarily reflects the Utility Registrants' portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and other postretirement benefit plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets. | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 16 – Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | No
Pension and Other Postretirement Benefits - Merger Related | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 16 – Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | Legacy Constellation - 2038 Legacy PHI - 2032 | No
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return
Deferred Income Taxes | Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information. | Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules. | No
AMI Programs - Deployment Costs | Installation costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters. | BGE - 2026 Pepco - 2027 DPL - 2030 | Yes
AMI Programs - Legacy Meters | Early retirement costs of legacy meters. | ComEd - 2028 PECO - 2020 BGE - 2028 Pepco - 2027 DPL - 2030 | ComEd, Pepco (District of Columbia), DPL (Delaware) - Yes PECO, BGE, Pepco (Maryland), DPL (Maryland) - No
AMI Programs - Post-test year incremental costs | Post-test year incremental program deployment costs of smart meters. As of December 31, 2018 and 2017, the portion of BGE's regulatory asset related to gas and electric costs was $10 million and $22 million, respectively. | BGE (gas) - 2021 BGE (electric) - Not currently being recovered. | BGE (gas) - Yes BGE (electric) - No
Electric distribution formula rate annual reconciliations | Under-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1 st. | 2020 | Yes
Electric distribution formula rate significant one-time events | Under-recoveries of electric distribution service costs related to significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event. | 2022 | Yes
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return
Energy Efficiency Costs | Costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure. | 2029 | Yes
Fair Value of Long-Term Debt | Represents the difference between the carrying value and fair value of long-term debt of PHI and BGE of $569 million and $133 million, respectively, as of December 30, 2018 and $619 million and $139 million, respectively, as of December 30, 2017, as of the PHI and Constellation merger dates. | BGE - 2043 PHI - 2045 | No
Fair Value of PHI’s Unamortized Energy Contracts | Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date. | 2036 | No
Asset Retirement Obligations | Future legally required removal costs associated with existing asset retirement obligations. | Over the life of the related assets. | Yes, once the removal activities have been performed.
MGP Remediation Costs | Environmental remediation costs for MGP sites. | Over the expected remediation period. See Note 22 - Commitments and Contingencies for additional information. | ComEd, PECO - No
Renewable Energy | Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts. | 2032 | No
Electric Energy and Natural Gas Costs | Under (over) recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders. | 2025 | DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No
Transmission formula rate annual reconciliations | Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1 st. | 2020 | Yes
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return
Energy efficiency and demand response programs | Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers. | PECO - 2021 BGE - 2023 Pepco, DPL - 2033 | BGE, Pepco, DPL, ACE - Yes PECO - Yes on capital investment recovered through this mechanism
Merger Integration Costs | Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $9 million each as of December 31, 2018 and $11 million and $9 million, respectively, as of December 31, 2017. | BGE - 2021 Pepco - 2021 DPL- 2023 ACE - Not currently being recovered. | BGE, Pepco (Maryland), DPL - Yes Pepco (District of Columbia), ACE - No
Under (Over)-Recovered Revenue Decoupling | Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms. | BGE, Pepco and DPL - 2019 | BGE, Pepco, DPL- No
Securitized Stranded Costs | Represents certain stranded costs associated with ACE's former electricity generation business. | 2022 | Yes
Removal Costs | For PHI, Pepco, DPL and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, PHI, Pepco and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes. | PHI, Pepco, DPL and ACE - Asset is generally recovered over the life of the underlining assets. ComEd, BGE, PHI, Pepco and DPL - The liability is reduced as costs are incurred. | Yes
DC PLUG Charge | Costs associated with the DC Plug Initiative. See District of Columbia Regulatory Matters discussion above. | 2019 - $30M $127 million to be determined based on future biennial plans filed with the DCPSC. | Portion of asset funded by Pepco-Yes
Deferred Storm Costs | For Pepco, DPL and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions. | Pepco - 2022 DPL - 2023 ACE - 2020 | Pepco, DPL - Yes ACE - No
Nuclear Decommissioning | Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 15 - Asset Retirement Obligations for additional information | Not currently being refunded. | No
Capitalized Ratemaking Amounts Not Recognized The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
| Exelon |  | ComEd(a) |  | PECO |  | BGE(b) |  | PHI |  | Pepco(c) |  | DPL(c) |  | ACE
December 31, 2018 | $ | 65 |  |  | $ | 8 |  |  | $ | — |  |  | $ | 49 |  |  | $ | 8 |  |  | $ | 5 |  |  | $ | 3 |  |  | $ | — |
December 31, 2017 | $ | 69 |  |  | $ | 6 |  |  | $ | — |  |  | $ | 53 |  |  | $ | 10 |  |  | $ | 6 |  |  | $ | 4 |  |  | $ | — |
__________
(a) | Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.
(b) | BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
(c) | Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.
Generation Regulatory Matters (Exelon and Generation) Illinois Regulatory Matters Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the required ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue, with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. For the year ended December 31, 2018, Generation recognized revenue of $373 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017. On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits, which were granted by the district court. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. The U.S. Circuit Court of Appeals for the Seventh Circuit panel denied the plaintiffs’ request for rehearing on October 9, 2018. On January 7, 2019, plaintiffs filed a petition seeking Supreme Court review of the case. New Jersey Regulatory Matters New Jersey Clean Energy Legislation. On May 23, 2018, the Governor of New Jersey signed new legislation, effective immediately, that will establish a ZEC program providing 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. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. Selected nuclear plants will receive annual ZEC payments for each energy year (12-month period from June 1 through May 31) within 90 days after the completion of such energy year. The quantity of ZECs issued will be determined based on the greater of 40% of the total number of MWh of electricity distributed by the public electric distribution utilities in New Jersey in the prior year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. The ZEC price is approximately $10 per MWh during the first 3-year eligibility period. For eligibility periods following the first 3-year eligibility period, the NJBPU has discretion to reduce the ZEC price. On November 19, 2018, the NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On the same day, Generation filed certain Supplemental Information with the NJBPU providing proprietary information that was requested in the application but which could not be shared with PSEG. The NJBPU must complete its processes for determining eligibility for, and participation in, the ZEC program by April 18, 2019. See Note 8 - Early Plant Retirements for additional information on New Jersey’s ZEC program potential impacts to PSEG’s Salem nuclear plant. New York Regulatory Matters New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which included a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that met specific criteria demonstrating public necessity, determined by the NYPSC to be Generation's FitzPatrick, Ginna and Nine Mile Point nuclear facilities. The New York State Energy Research and Development Authority (NYSERDA) centrally procures the ZECs through a 12-year contract extending from April 1, 2017 through March 31, 2029, administered in six two-year tranches. ZEC payments are made based upon the number of MWh produced by each facility, subject to specified caps and minimum performance requirements. The ZEC price for the first tranche was set at $17.48 per MWh of production and is administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increases in underlying energy and capacity prices. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) is required to purchase an amount of ZECs from NYSERDA equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers is incorporated into the commodity charges on customer bills. Generation is currently recognizing revenue for the sale of New York ZECs in the month they are generated and for the years ended December 31, 2018 and 2017, Generation has recognized revenue of $438 million and $311 million, respectively. On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors. On December 9, 2016, several parties filed motions to intervene in the case and to dismiss the lawsuit. On July 25, 2017, the court granted the motions to dismiss. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking Supreme Court review of the case. In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. Generation, CENG and the state's answers and briefs were filed on March 30, 2018. On December 17, 2018, plaintiffs filed a reply brief introducing new arguments and new evidence. The State of New York filed a motion to strike on December 28, 2018. On January 4, 2019, Generation and CENG filed a motion to strike the new arguments and new evidence. After briefing is completed, the court will decide whether or not to set the case for hearing. Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 8 - Early Plant Retirements for additional information related to Ginna and Nine Mile Point, and Note 5 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick. Ginna Nuclear Power Plant Reliability Support Services Agreement. In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a RSSA to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time. On April 8, 2016, FERC accepted Ginna’s compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment of $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment was removed from Generation’s results of operations as a result of the noncontrolling interests in CENG. The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 8 - Early Plant Retirements for additional information regarding the impacts of a decision to early retire a nuclear plant. Federal Regulatory Matters Operating License Renewals Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) with Maryland Department of the Environment (MDE) for Conowingo, Generation continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. On April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a Settlement Agreement resolving all fish passage issues between the parties. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license. On April 27, 2018, the MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact on Exelon’s and Generation’s financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous violating MDE regulations, state, federal, and constitutional law. Generation also requested that FERC defer action on the federal license while these significant state and federal law issues are pending. On July 9, 2018, MDE filed a motion to dismiss Generation's complaint in state court, which was granted without prejudice on October 9, 2018. The court found MDE's Certification was not a "final decision" of Exelon's rights and because Exelon's motion for reconsideration remains pending, as does its administrative appeal of the 401 Certification, there was no final administrative decision for the court to review at this time. On November 5, 2018, Exelon appealed the Maryland Circuit Court's dismissal of Exelon's state complaint. Exelon continues to challenge the 401 Certification through the administrative process and in federal court. Exelon and Generation cannot predict the final outcome or its financial impact, if any, on Exelon or Generation. As of December 31, 2018, $37 million of direct costs associated with Conowingo licensing efforts have been capitalized. Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3. Generation anticipates the second license renewal process to take approximately 2 years from the application submission until completion of the NRC’s review process. Peach Bottom Units 2 and 3 are currently licensed to operate through 2033 and 2034, respectively. PJM Transmission Rate Design. Refer to Other Federal Regulatory Matters above for additional information.

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