5. Regulatory Matters (All Registrants)

Except for the matters noted below, the disclosures set forth in Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K reflect, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Regulatory Matters

Distribution Formula Rate (Exelon and ComEd). On April 13, 2017, ComEd filed its annual distribution formula rate with the ICC pursuant to EIMA. The filing establishes the revenue requirement used to set the rates that will take effect in January 2018 after the ICC’s review and approval, which is due by December 2017. The revenue requirement requested is based on 2016 actual costs plus projected 2017 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2016 to the actual costs incurred that year. ComEd's 2017 filing request includes a total 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 revenue requirement for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.47% inclusive of an allowed ROE of 8.40%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2016 provided for a weighted average debt and equity return on distribution rate base of 6.45% inclusive of an allowed ROE of 8.34%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 6 basis points. See table below for ComEd's regulatory assets associated with its distribution formula rate. For additional information on ComEd's distribution formula rate filings see Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K.

On December 6, 2016, the ICC issued a final order approving the 2016 distribution formula rate, which included a total increase to the revenue requirement of $127 million, reflecting an increase of $134 million for the initial revenue requirement for 2016 and a decrease of $7 million related to the annual reconciliation for 2015. On December 20, 2016, the ICC granted ComEd's and other parties' joint application for rehearing on the impact that changing ComEd’s OSHA recordable rate for 2014 and 2015 has on the revenue requirement approved in this order. On March 22, 2017, the ICC issued an order approving ComEd's proposal to reduce the 2016 revenue requirement by $18 million, which will be reflected in customer rates in 2017.

Illinois Future Energy Jobs Act (Exelon, Generation, and ComEd).

Background

On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA is effective June 1, 2017, and includes, among other provisions, (1) a ZES providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd, (4) revisions to the Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates exceeds specified limits, (6) revisions to the existing net metering statute to (i) mandate net metering for community generation projects, and establish billing procedures for subscribers to those projects, (ii) provide immediately for netting at the energy-only rate for nonresidential customers, and (iii) transition from netting at the full retail rate to the energy-only rate for certain residential net metering customers once the net meter customer load equals 5% of total peak demand supplied in the previous year and (7) support for low income rooftop and community solar programs.

Zero Emission Standard

FEJA includes a ZES that provides compensation through the procurement of ZECs targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet specific eligibility criteria. ZES will have a 10-year duration extending through May 31, 2027. Eligible generators may participate in a procurement event overseen by the IPA and selected generators will directly contract with Illinois utilities for the procurement of the ZECs based upon the number of MWh produced by the eligible facilities, subject to specified annual caps. The ZEC price will be based upon the current social cost of carbon as determined by the federal government and is initially established at $16.50 per MWh of production, subject to future adjustments based on specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices.

Illinois utilities, including ComEd, will be required to purchase from eligible nuclear facilities an amount of ZECs equivalent to 16% of the actual amount of electricity delivered in 2014. ComEd will recover all costs associated with purchasing ZECs through a new rate rider, which will provide for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase ZECs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods.

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. One lawsuit was filed by customers of ComEd, led by the Village of Old Mill Creek, and the other was brought by the EPSA and three other electric suppliers. Both lawsuits argue that the Illinois ZEC program will distort FERC’s energy and capacity market auction system of setting wholesale prices, and seek a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits. These motions are currently pending. In addition, on March 31, 2017, plaintiffs in both lawsuits filed motions for preliminary injunction with the court. Exelon cannot predict the outcome of these lawsuits. It is possible that resolution of these matters could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, financial positions and cash flows.

See Note 7 - Early Nuclear Plant Retirements for the impacts of the provisions above on Generation’s Consolidated Balance Sheets and Consolidated Statements of Operations and Comprehensive Income. These provisions do not impact ComEd’s Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income or Consolidated Statements of Cash Flows until second quarter of 2017.

ComEd Electric Distribution Rates

FEJA extends the sunset date for ComEd’s performance-based electric distribution formula rate from 2019 to the end of 2022, allows ComEd to revise the electric distribution formula rate to eliminate the ROE collar, and allows ComEd to implement a decoupling tariff if the electric distribution formula rate is terminated at any time. ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to Operating revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began reflecting the impacts of this change in its electric distribution services costs regulatory asset beginning in first quarter 2017. As of March 31, 2017, ComEd recorded an increase to Operating revenues and its electric distribution services costs regulatory asset of approximately $16 million for this change.

FEJA requires ComEd to make non-recoverable contributions to low income energy assistance programs of $10 million per year for 5 years as long as the electric distribution formula rate remains in effect. With the exception of these contributions, ComEd will recover from customers, subject to certain caps explained below, the costs it incurs pursuant to FEJA either through its electric distribution formula rate or other recovery mechanisms.

Energy Efficiency

Existing Illinois law requires ComEd to implement cost-effective energy efficiency measures and, for a 10-year period ending May 31, 2018, cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers.

Beginning January 1, 2018, FEJA provides for new cumulative annual energy efficiency MWh savings goals for ComEd, which are designed to achieve 21.5% of cumulative persisting annual MWh savings by 2030, as compared to the deemed baseline of 88 million MWhs of electric power and energy sales. FEJA, deems the cumulative persisting annual MWh savings to be 6.6% from 2012 through the end of 2017. ComEd expects to spend approximately $250 million to $400 million annually from 2017 through 2030 to achieve these energy efficiency MWh savings goals. In addition, FEJA extends the peak demand reduction requirement from 2018 to 2026. Because the new requirements apply beginning in 2018, FEJA extends the existing energy efficiency plans, which were due to end on May 31, 2017, through December 31, 2017. FEJA also exempts customers with demands over 10 MW from energy efficiency plans and requirements beginning June 1, 2017.

FEJA allows ComEd to cancel its existing energy efficiency rate rider and replace it with an energy efficiency formula rate, and to defer energy efficiency costs (except for any voltage optimization costs which will be recovered through the electric distribution formula rate) as a separate regulatory asset that will be 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 will earn 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. 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 will be required to file an update to its energy efficiency formula rate on or before June 1 each year, with resulting rates effective in January of the following year. The annual update will be based on projected current year energy efficiency costs and the related projected year-end regulatory asset balance less any related deferred taxes. The update will also include a reconciliation of any differences between the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs and year-end energy efficiency regulatory asset balances less any related deferred taxes.

ComEd expects to cancel its existing energy efficiency rider after FEJA becomes effective on June 1, 2017, at which time it must perform a reconciliation of revenues and costs incurred through the cancellation date and issue a one-time credit on retail customers' bills for any over-recoveries. As of March 31, 2017, ComEd’s over-recoveries associated with its existing energy efficiency rider of $139 million were reflected in Current regulatory liabilities on Exelon’s and ComEd’s Consolidated Balance Sheets. ComEd expects to provide a one-time credit to customers in the second half of 2017 to address this over-recovery.

Renewable Portfolio Standard

Existing Illinois law requires ComEd to purchase each year an increasing percentage of renewable energy resources for the customers for which it supplies electricity. This obligation is satisfied through the procurement of RECs. FEJA revises the Illinois RPS to require ComEd to procure RECs for all retail customers by June 2019, regardless of the customers’ electricity supplier, and provides support for low-income rooftop and community solar programs, which will be funded by the existing Renewable Energy Resources Fund and ongoing RPS collections. ComEd will recover all costs associated with purchasing RECs through rate riders, which will provide for a reconciliation and true-up to actual costs, with any difference between revenues and expenses to be credited to or collected from ComEd’s retail customers in subsequent periods. The first reconciliation and true-up for RECs will cover revenues and costs for the four year period beginning June 1, 2017 through May 31, 2021. Subsequently, the RPS rate rider will provide for an annual reconciliation and true-up.

Customer Rate Increase Limitations

FEJA includes provisions intended to limit the average impact on ComEd customer rates for recovery of costs incurred under FEJA as follows: (1) for a typical ComEd residential customer, the average impact must be less than $0.25 cents per month, (2) for nonresidential customers with a peak demand less than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois commercial retail customers during 2015, and (3) for nonresidential customers with a peak demand greater than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois industrial retail customers during 2015.

By June 30, 2017, ComEd must submit a 10-year projection to the ICC of customer rate impacts for residential customers and nonresidential customers with a peak demand less than 10 MW. Thereafter, beginning in 2018, ComEd must submit a report to the ICC for residential customers and nonresidential customers with a peak demand less than 10 MW by February 15th and June 30th of each year, respectively. For nonresidential customers with a peak demand greater than 10 MW, ComEd must submit a report to the ICC by May 1 of each year if a rate reduction will be necessary in the following year. For residential customers, the reports will include the actual costs incurred under FEJA during the preceding year and a rolling 10-year customer rate impact projection. The reports for nonresidential customers with a peak demand less than 10 MW will also include the actual costs incurred under FEJA during the preceding year, as well as the average annual rate increase from January 1, 2017 through the end of the preceding year and the average annual rate increase projected for the remainder of the 10-year period.

If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the first four years, ComEd is required to decrease costs associated with FEJA investments, including reductions to ZEC contract quantities. If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the last six years, ComEd is required to demonstrate how it will reduce FEJA investments to ensure compliance. If the actual residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations for any one year, ComEd is required to submit a corrective action plan to decrease future year costs to reduce customer rates to ensure future compliance. If the actual residential customer or nonresidential customer rate exceeds the limitations for two consecutive years, ComEd can offer to credit customers for amounts billed in excess of the limitations or ComEd can terminate FEJA investments. If ComEd chooses to terminate FEJA investments, the ICC shall order termination of ZEC contracts and further initiate proceedings to reduce energy efficiency savings goals and terminate support for low-income rooftop and community solar programs. ComEd is allowed to fully recover all costs incurred as of and up to the date of the programs’ termination.

For the energy efficiency formula, ComEd will record a regulatory asset or liability and corresponding increase or decrease to Operating revenues for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. For the other rate riders to be established under FEJA, ComEd will record a regulatory asset or liability for any differences between revenues and incurred expenses.

Other than recognizing the impacts of eliminating the ROE collar in its electric distribution formula rate, FEJA did not have any impacts on ComEd’s Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income or Consolidated Statements of Cash Flows in first quarter 2017.

Energy Efficiency and Renewable Energy Resources (Exelon and ComEd). In accordance with legislation in effect on December 31, 2016, the IPA's Procurement Plans include the procurement of cost-effective renewable energy resources in amounts that equal or exceed a minimum target percentage of the total electricity that each electric utility supplies to its eligible retail customers. The June 1, 2016 target renewable energy resources obligation for the utilities was at least 11.5%. This obligation increases by at least 1.5% each year thereafter to an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth by Illinois legislation. As of March 31, 2017, ComEd had purchased renewable energy resources or equivalents, such as RECs, in accordance with the IPA Procurement Plan. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates.

In accordance with FEJA that takes effect on June 1, 2017, beginning with the plan or plans to be implemented in the 2017 delivery year, the IPA shall develop a long term renewable resources procurement plan (LT Plan). The RPS target percentages for the overall service territory have not changed through June 1, 2025 although FEJA extended the 25% RPS target to delivery years after 2025. Currently, each RES and each utility is responsible for the renewable resource obligation of the customers it supplies power for. Over time, this will change and the utility will procure renewable resources based on the retail load of substantially all customers in its service territory. For the delivery year beginning June 1, 2017, the LT Plan shall include cost effective renewable energy resources procured by the utility for the retail load the utility supplies and for 50% of the retail customer load supplied by Retail Electric Suppliers in the utility service territory on February 28, 2017. Utility procurement for RES supplied retail customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019.

Grand Prairie Gateway Transmission Line (Exelon and ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On October 22, 2014, the ICC issued an Order approving ComEd’s request. The City of Elgin and certain other parties each filed an appeal of the ICC Order in the Illinois Appellate Court for the Second District. ComEd then reached a settlement of the appeal filed by all parties except Elgin. On March 31, 2016, the Illinois Appellate Court issued its opinion affirming the ICC’s grant of a certificate to ComEd to construct and operate the line. Elgin did not seek further review of the Illinois Appellate Court decision. ComEd acquired the necessary land rights across the project route through voluntary transactions. ComEd began construction of the line during 2015 and placed the line in-service on April 7, 2017.

Pennsylvania Regulatory Matters

Pennsylvania Procurement Proceedings (Exelon and PECO). Through PECO’s PAPUC approved DSP Programs, PECO procures electric supply for its default electric customers through PAPUC approved competitive procurements.

On March 17, 2016, PECO filed its fourth DSP Program with the PAPUC proposing a 24-month term from June 1, 2017 through May 31, 2019, in compliance with electric generation procurement guidelines set forth in Act 129. On December 8, 2016, the PAPUC approved the fourth DSP Program for the modified 48-month term and deferred CAP Shopping to another proceeding. OCA and Low Income Advocates subsequently filed a Petition for Reconsideration and Clarification related to CAP Shopping. On March 16, 2017 the PAPUC granted reconsideration and consolidated the proceeding with the DSP II docket, which includes the pending CAP Shopping plan that would allow low-income CAP customers to purchase their generation supply from EGSs. PAPUC referred the consolidated proceedings to the Office of Administrative Law Judge for hearing and decision.

Pennsylvania Act 11 of 2012 (Exelon and PECO). In February 2012, Act 11 was signed into law, which provided the PAPUC authority to approve the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to a DSIC, the PAPUC's implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by the Commission, which outlines how the utility is planning to increase its investment for repairing, improving or replacing aging infrastructure. The PAPUC approved PECO’s petition for its proposed electric DSIC and LTIIP on October 22, 2015 for spending of $275 million over a 5 year period through 2020. On March 1, 2017, PECO filed a petition with the PAPUC for approval of a Modified Gas LTIIP to increase expenditures to $762 million from the approved $534 million over the 10 year LTIIP period through 2022.

Maryland Regulatory Matters

2017 Maryland Electric Distribution Rates (Exelon, PHI and Pepco). On March 24, 2017, Pepco filed an application with the MDPSC requesting an increase of $69 million based on a ROE of 10.1%. The application includes a request for an income tax adjustment to reflect full normalization of removal costs associated with pre-1981 property, which accounts for $18 million of the requested increase. Pepco expects a decision in the matter in the fourth quarter of 2017, but cannot predict how much of the requested rate increase the MDPSC will approve or if it will approve the requested income tax adjustment.

2016 Maryland Electric Distribution Rates (Exelon, PHI and DPL). On February 15, 2017, the MDPSC approved an increase in DPL electric distribution rates of $38 million based on a ROE of 9.6%. The new rates became effective for services rendered on or after February 15, 2017. The MDPSC also denied DPL’s request to continue its Grid Resiliency Program, through which DPL proposed to invest $4.6 million a year for two years to improve priority feeders and install single-phase reclosing fuse technology. The final order did not result in the recognition of any incremental regulatory assets or liabilities during the first quarter of 2017.

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 all of its SOS-related costs. The Administrative Charge is now comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which is an adder to the utility’s SOS rate to act as a proxy for retail suppliers’ costs. The Commission accepted BGE positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a modest return on the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. On December 16, 2016, MDPSC Staff requested clarification concerning the amount of return on the SOS awarded to BGE and on December 19, 2016, the residential consumer advocate sought rehearing of the return awarded. On January 24, 2017, the MDPSC issued an order denying the MDPSC Staff request for clarification and the residential consumer advocate request for rehearing. On February 22, 2017, the residential consumer advocate filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore City. 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. As of March 31, 2017 and December 31, 2016, the balance of BGE's regulatory asset was $225 million and $230 million, respectively, representing incremental program deployment costs. The current quarter balance of $225 million consists of three major components, including $140 million of unamortized incremental deployment costs of the AMI program, $53 million of unamortized costs of the non-AMI meters replaced under the program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. The balance as of March 31, 2017 reflects the impact of the cost disallowances and adjustments discussed below. The incremental deployment costs for the AMI program and the non-AMI meter components of the regulatory asset are being recovered through rates and amortized to expense over a 10 year period, while the post-test year incremental program deployment costs have not yet been approved for recovery by the MDPSC. A return on the regulatory asset is currently included in rates, except for the $53 million portion representing the unamortized cost of the retired non-AMI meters and a $32 million portion related to post-test year incremental program deployment costs.

As a combined result of the MDPSC orders in BGE's 2015 electric and natural gas distribution 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 non-AMI plant costs from Property, plant and equipment, net to Regulatory assets on Exelon's and BGE's Consolidated Balance Sheets. For further information, see Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K.

Delaware Regulatory Matters

Gas Cost Rates (Exelon, PHI and DPL). DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2016, DPL made its 2016-2017 GCR filing. The rates proposed in the 2016-2017 GCR filing resulted in a GCR increase of approximately 14%. On September 20, 2016, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2016, subject to refund and pending final DPSC approval. A settlement agreement was reached by all parties. On April 20, 2017, the DPSC issued an order which approved the settlement agreement and made the rates approved as final effective November 1, 2016.

2016 Electric and Natural Gas Distribution Rates (Exelon, PHI and DPL). On May 17, 2016, DPL filed an application with the DPSC to increase its annual electric and natural gas distribution rates by $63 million (which was updated to $60 million on March 8, 2017) and $22 million, respectively, based on a requested ROE of 10.6%. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allowed DPL to put into effect $2.5 million of each of the rate increases two months after filing the applications which were effective July 16, 2016. On December 17, 2016, the DPSC approved that an additional $30 million in electric distribution rates be implemented effective December 17, 2016, subject to refund based on the final DPSC order, and an additional $10 million in natural gas distribution rates be implemented effective December 17, 2016, subject to refund based on the final DPSC order.

On March 8, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate, Delaware Electric Users Group and the DPSC Staff in its electric distribution rate proceeding, which provides for an increase in DPL electric distribution rates of $31.5 million based on an ROE of 9.7%. The settlement agreement also provides that the rates currently in effect, as approved by the DPSC, effective July 16, 2016 and December 17, 2016 (as discussed above), will remain in effect until the date of the final DPSC order and that no refund will be required. As a result, during the first quarter of 2017, DPL established a regulatory asset of $8 million for costs incurred to achieve the merger and reversed a regulatory liability of $1 million for electric revenues that are no longer subject to refund which resulted in an increase in net income of $5 million. DPL currently expects a final order on the settlement agreement during the second quarter of 2017.

On April 6, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate and the DPSC Staff in its natural gas distribution rate proceeding, which provides for an increase in DPL natural gas distribution rates of $4.9 million based on an ROE of 9.7%. The settlement agreement also provides that DPL will refund amounts in excess of the $4.9 million increase collected under the temporary rates effective July 16, 2016 and December 17, 2016 (as discussed above), and that the new rates will be effective within thirty days of DPSC approval of the settlement agreement. In the event that the final order reflects the settlement agreement, DPL does not expect the impact to be material to its financial statements. DPL currently expects a final order on the settlement agreement during the second quarter of 2017.

District of Columbia Regulatory Matters

2016 Electric Distribution Rates (Exelon, PHI and Pepco). On June 30, 2016, Pepco filed an application with the DCPSC to increase its annual electric distribution rates by $86 million, which was updated to $82 million on October 14, 2016, and further updated to approximately $77 million on February 1, 2017, based on a requested ROE of 10.6%. The DCPSC has issued a procedural schedule indicating a final decision will be issued by July 25, 2017. Any adjustments to its rates approved by the DCPSC are expected to take effect soon thereafter. Pepco cannot predict how much of the requested increase the DCPSC will approve.

On April 18, 2016, a party to a separate DCPSC proceeding filed a motion to suspend Pepco’s bill stabilization adjustment (BSA), which decouples distribution revenues from utility customers from the amount of electricity delivered. On September 9, 2016, the DCPSC denied the party’s motion and determined that the appropriate forum in which to determine whether the BSA continues to be just and reasonable is in Pepco’s rate case proceeding. In addition, the DCPSC stated that it was putting Pepco on notice that all funds collected for the BSA from January 2015 to the issuance of a decision in the rate case proceeding are subject to refund should the DCPSC determine that such funds were not justly or reasonably collected. On November 22, 2016, following Pepco's October 7, 2016 request for reconsideration of the order, the DCPSC issued an order stating that its September 9, 2016 order was not final and confirming that issues related to the BSA, including potential remedial actions, would be addressed in Pepco's rate case. Pepco cannot predict the outcome of this matter or the impact of a refund if ordered by the DCPSC.

District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). The Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act) was the enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a $1 billion project to selectively place underground some of the District of Columbia’s most outage-prone power lines.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a volumetric surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be funded by the District of Columbia through the issuance of securitized bonds, which bonds will be repaid through a volumetric surcharge (the DDOT surcharge) on the electric bills of Pepco District of Columbia customers that Pepco will remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be funded by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

In June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune.

In March 2017, the Electric Company Infrastructure Improvement Financing Amendment Act of 2017 was introduced to the Council of the District of Columbia. The proposed amendment changes a portion of the funding structure for the DC PLUG initiative from securitized bonds issued by the District to a pay-as-you-go structure with the cost imposed on the electric company and recovered by the electric company through a rate rider. This amendment would reduce the overall project authorization from $1 billion to $500 million and would provide that: (i) Pepco is to fund approximately $250 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a volumetric surcharge on the electric bills of Pepco District of Columbia customers; (ii) $188 million of the DC PLUG initiative cost would be funded through a charge collected from Pepco by the District of Columbia and Pepco would recover this charge from customers through a volumetric distribution rider; and; (iii) the remaining costs up to $62 million are to be covered by the existing capital projects program of DDOT. Pepco will not earn a return on or a return of the cost of the assets funded by the charge collected from Pepco by the District of Columbia or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount upon completion.

PHI believes that the proposed amendment addresses the assertion made by an agency of the federal government that the surcharge proposed in the Improvement Financing Act constitutes a tax on end users.

New Jersey Regulatory Matters

2017 Electric Distribution Rates (Exelon, PHI and ACE). On March 30, 2017, ACE submitted an application with the NJBPU to increase its electric distribution rates by approximately $70 million (before New Jersey sales and use tax), based upon a requested ROE of 10.1%. The application also requests approval of a rate surcharge mechanism called the “System Renewal Recovery Charge,” which would permit more timely recovery of certain costs associated with reliability and system renewal-related capital investments. ACE currently expects a decision in this matter in the first quarter of 2018, but cannot predict if the NJBPU will approve the application as filed.

2016 Electric Distribution Rates (Exelon, PHI and ACE). On August 24, 2016, the NJBPU issued an order approving a stipulation of settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff and Unimin Corporation, which, among other things, provided that a determination on ACE's grid resiliency program, PowerAhead, would be separated into a phase II of the rate proceeding and decided at a later date PowerAhead includes capital investments to advance modernization of the electric grid through energy efficiency, increased distributed generation, and resiliency, focused on improving the distribution system's ability to withstand major storm events. ACE currently expects this matter to conclude in the second quarter of 2017, but cannot predict if the NJBPU will approve the PowerAhead initiative.

Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE). On February 1, 2017, ACE submitted its 2017 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts. The net impact of adjusting the charges as proposed is an overall annual rate decrease of approximately $29 million (revised to approximately $32 million in April 2017, based upon an update for actuals through March 2017), including New Jersey sales and use tax. The matter is pending at the NJBPU. ACE has requested that the NJBPU place the new rates into effect by June 1, 2017. There is no assurance that NJBPU will put final rates in effect by the requested date.

New York Regulatory Matters

New York Clean Energy Standard (Exelon, Generation). On August 1, 2016, the New York Public Service Commission (NYPSC) issued an order establishing the CES, a component of which is the Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC. The New York State Energy Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a 12-year contract, to be administered in six two-year tranches, extending from April 1, 2017 through March 31, 2029. ZEC payments will be made to the eligible resources based upon the number of MWh produced, subject to specified caps and minimum performance requirements. The price to be paid for the ZECs under each tranche will be 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 increase in underlying energy and capacity prices. The ZEC price for the first tranche has been set at $17.48 per MWh of production. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) shall be required to purchase an amount of ZECs equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers shall be incorporated into the commodity charges on customer bills.

The NYPSC initially identified three plants eligible for the ZEC program: the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. As issued, the order also provided that the duration of the program beyond the first tranche was conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018. On November 18, 2016, the required contracts with NYSERDA were executed for Ginna and Nine Mile Point, in addition to Entergy’s execution of the required contract for the FitzPatrick facility. On March 31, 2017, Generation closed on the acquisition of FitzPatrick.

Several parties filed with the NYPSC requests for rehearing or reconsideration of the CES. Generation and CENG also filed a request for clarification, or in the alternative limited rehearing, that the condition limiting the duration of the program beyond the first tranche be limited to the eligibility of the FitzPatrick plant only and have no bearing on Ginna or Nine Mile Point’s eligibility for the full 12-year duration. On December 15, 2016, the NYPSC approved Generation’s and CENG's petition to clarify this condition and denied all petitions for rehearing of the CES. Parties have until mid-April to appeal to New York State court the denials of the requests for rehearing. In addition, a Petition seeking to invalidate the ZEC program was filed in New York State court by certain environmental groups and other parties on November 30, 2016, and amended on January 13, 2017, arguing that the NYPSC violated certain technical provisions of the State Administrative Procedures Act (SAPA) when adopting the ZEC program. On February 15, 2017, Generation and CENG filed a motion to dismiss the state court action. The NYPSC also filed a motion to dismiss the state court action. On March 24, 2017, the plaintiffs filed a memorandum of law opposing the motions to dismiss, and Generation and CENG filed a reply brief on April 28, 2017. The motion is pending.

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, Generation and CENG filed a motion to intervene in the case and to dismiss the lawsuit. The motion to intervene has been granted and the motion to dismiss is pending.

Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 7 - Early Nuclear Plant Retirements for additional information relative to Ginna and Nine Mile Point. See Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). 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 Reliability Support Services Agreement (RSSA) to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time. During 2015 and 2016, Ginna and RG&E made filings with the NYPSC and FERC for their approval of the proposed RSSA. Although the RSSA was still subject to regulatory approvals, on April 1, 2015, Ginna began delivering the power and capacity from the Ginna plant into the ISO-NY consistent with the technical provisions of the RSSA.

On March 22, 2016, Ginna submitted a compliance filing with FERC with revisions to the RSSA requested by FERC. On April 8, 2016, FERC accepted the 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 approximately $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 CES. As stated previously, on November 18, 2016 the required contract with NYSERDA was executed by Generation and CENG for Ginna. Upon the expiry of the RSSA on March 31, 2017, Ginna is required to make refund payments of $20 million to RG&E related to capital expenditures. Ginna has been deferring recognition for a portion of the monthly revenue received under the RSSA related to this obligation, and Ginna expects to pay RGE the $20 million in June 2017. Additionally, the provisions of the RSSA provided for a one-time payment of $12 million to be paid from RGE to Ginna at the end of the contract. This $12 million was recognized in revenue as of March 31, 2017. Subject to prevailing over any administrative or legal challenges, it is expected the CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 7-Early Nuclear Plant Retirements for further information regarding the impacts of a decision to early retire one or more nuclear plants.

Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd and BGE). The following total increases/(decreases) were included in ComEd’s and BGE’s electric transmission formula rate filings:



	2017
Annual Transmission Filings^(a)	ComEd			BGE
Initial revenue requirement increase	$	44		$	31
Annual reconciliation (decrease) increase	(33		)	3
Dedicated facilities decrease ^(b)	—			(8		)
Total revenue requirement increase	$	11		$	26

Allowed return on rate base ^(c)	8.43		%	7.47		%
Allowed ROE ^(d)	11.50		%	10.50		%

_____________

(a) All rates are effective June 2017, subject to review by the FERC and other parties, which is due by fourth quarter 2017.

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


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

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

For additional information regarding transmission formula rate filings see Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K.

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 would 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. PECO cannot predict how much, if any, of a transmission rate increase FERC may approve or when the rate increase may go into effect.

PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO, BGE, Pepco, DPL and ACE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. A number of parties appealed to the U.S. Court of Appeals for the Seventh Circuit for review of the decision.

In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On remand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. On June 15, 2016, a number of parties, including Exelon and the Utility Registrants filed a proposed Settlement with FERC. If the Settlement is approved, 50% of the costs of the 500 kV and above facilities approved by the PJM Board on or before February 1, 2013 will be socialized across PJM and 50% will be allocated according to a formula that calculates the flows on the transmission facilities. Each state that is a party in this proceeding either signed, or did not oppose, the settlement. The Settlement is opposed by a number of merchant transmission owners and New York load-serving entities. The Settlement includes provisions for monthly credits or charges that are expected to be mostly refunded or recovered through customer rates over a 10-year period based on negotiated numbers for charges prior to January 1, 2016.

Exelon expects that the Settlement will not have a material impact on the results of operations, cash flows and financial position of Generation, ComEd, PECO, BGE, Pepco, DPL or ACE. The Settlement is subject to approval by FERC.

Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs (Exelon and Generation). PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to remove the revenues it receives through a federal, state or other government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new resources. Exelon has generally opposed policies that require subsidies or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.

On January 9, 2017, the Electric Power Supply Association (EPSA) filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation's facilities expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.

Operating License Renewals (Exelon and Generation). 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 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. In addition, Generation continues to work with MDE and other Federal and Maryland state agencies to conduct and fund an additional sediment and nutrient monitoring study.

On April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all fish passage issues between the parties. Accordingly, on April 22, 2016, Exelon withdrew its Request for a Trial-Type Hearing and Alternative Prescription. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the 46-year 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. Resolution of the remaining issues relating to Conowingo involving various stakeholders may have a material effect on Exelon’s and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs. As of March 31, 2017, $29 million of direct costs associated with Conowingo licensing efforts have been capitalized. See Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K for additional information on Generation's operating license renewal efforts.

Regulatory Assets and Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, 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.

As a result of applying the acquisition method of accounting and pushing it down to the consolidated financial statements of PHI, certain regulatory assets and liabilities were established at Exelon and PHI to offset the impacts of fair valuing the acquired assets and liabilities assumed which are subject to regulatory recovery. In total, Exelon and PHI recorded a net $2.4 billion regulatory asset reflecting adjustments recorded as a result of the acquisition method of accounting. See Note 4 — Mergers, Acquisitions and Dispositions for additional information.

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of March 31, 2017 and December 31, 2016. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K.



									Successor
March 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits ^(a)	$	4,152	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes ^(b)	2,055		76		1,617		101		261		169		40		52
AMI programs	689		165		46		225		253		170		83		—
Under-recovered distribution service costs ^(c)	211		211		—		—		—		—		—		—
Debt costs	122		41		1		7		80		17		9		6
Fair value of long-term debt	797		—		—		—		658		—		—		—
Fair value of PHI's unamortized energy contracts	1,021		—		—		—		1,021		—		—		—
Severance	4		—		—		4		—		—		—		—
Asset retirement obligations	116		82		22		12		—		—		—		—
MGP remediation costs	296		271		25		—		—		—		—		—
Under-recovered uncollectible accounts	63		63		—		—		—		—		—		—
Renewable energy	285		282		—		—		3		—		1		2
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}	71		18		—		19		34		6		5		23
Deferred storm costs	39		—		—		1		38		12		7		19
Electric generation-related regulatory asset	8		—		—		8		—		—		—		—
Energy efficiency and demand response programs	596		—		1		269		326		241		84		1
Merger integration costs ^(j)(k)	32		—		—		8		24		11		13		—
Under-recovered revenue decoupling ^(l)	76		—		—		31		45		36		9		—
COPCO acquisition adjustment	7		—		—		—		7		—		7		—
Recoverable Workers compensation and long-term disability cost	33		—		—		—		33		33		—		—
Vacation accrual	42		—		17		—		25		—		15		10
Securitized stranded costs	123		—		—		—		123		—		—		123
CAP arrearage	11		—		11		—		—		—		—		—
Removal costs	486		—		—		—		486		136		90		261
Other	46		6		8		5		27		21		4		4
Total regulatory assets	11,381		1,215		1,748		690		3,444		852		367		501
Less: current portion	1,330		183		40		191		653		173		66		94
Total non-current regulatory assets	$	10,051	$	1,032	$	1,708	$	499	$	2,791	$	679	$	301	$	407



									Successor
March 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	48	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,776		2,294		482		—		—		—		—		—
Removal costs	1,598		1,328		—		136		134		17		117		—
Deferred rent	39		—		—		—		39		—		—		—
Energy efficiency and demand response programs	185		139		44		—		2		2		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	66		—		66		—		—		—		—		—
Gas distribution tax repairs	18		—		18		—		—		—		—		—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}	133		38		66		2		27		7		12		8
Rate stabilization deferral	3		—		—		3		—		—		—		—
Other	65		4		7		20		34		3		13		17
Total regulatory liabilities	4,939		3,803		691		161		236		29		142		25
Less: current portion	637		311		161		67		82		10		47		25
Total non-current regulatory liabilities	$	4,302	$	3,492	$	530	$	94	$	154	$	19	$	95	$	—



									Successor
December 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits ^(a)	$	4,162	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes ^(b)	2,016		75		1,583		98		260		171		38		51
AMI programs	701		164		49		230		258		174		84		—
Under-recovered distribution service costs ^(c)	188		188		—		—		—		—		—		—
Debt costs	124		42		1		7		81		17		9		6
Fair value of long-term debt	812		—		—		—		671		—		—		—
Fair value of PHI's unamortized energy contracts	1,085		—		—		—		1,085		—		—		—
Severance	5		—		—		5		—		—		—		—
Asset retirement obligations	111		76		23		12		—		—		—		—
MGP remediation costs	305		278		26		1		—		—		—		—
Under-recovered uncollectible accounts	56		56		—		—		—		—		—		—
Renewable energy	260		258		—		—		2		—		—		2
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}	89		23		—		38		28		6		5		17
Deferred storm costs	36		—		—		1		35		12		5		18
Electric generation-related regulatory asset	10		—		—		10		—		—		—		—
Rate stabilization deferral	7		—		—		7		—		—		—		—
Energy efficiency and demand response programs	621		—		1		285		335		250		85		—
Merger integration costs ^(j)(k)	25		—		—		10		15		11		4		—
Under-recovered revenue decoupling ^(l)	27		—		—		3		24		21		3		—
COPCO acquisition adjustment	8		—		—		—		8		—		8		—
Workers compensation and long-term disability costs	34		—		—		—		34		34		—		—
Vacation accrual	31		—		7		—		24		—		14		10
Securitized stranded costs	138		—		—		—		138		—		—		138
CAP arrearage	11		—		11		—		—		—		—		—
Removal costs	477		—		—		—		477		134		88		255
Other	49		7		9		5		29		22		5		4
Total regulatory assets	11,388		1,167		1,710		712		3,504		852		348		501
Less: current portion	1,342		190		29		208		653		162		59		96
Total non-current regulatory assets	$	10,046	$	977	$	1,681	$	504	$	2,851	$	690	$	289	$	405



									Successor
December 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	47	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,607		2,169		438		—		—		—		—		—
Removal costs	1,601		1,324		—		141		136		18		118		—
Deferred rent	39		—		—		—		39		—		—		—
Energy efficiency and demand response programs	185		141		41		—		3		3		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	76		—		76		—		—		—		—		—
Gas distribution tax repairs	20		—		20		—		—		—		—		—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}	134		60		56		—		18		8		5		5
Other	72		4		5		19		41		2		17		20
Total regulatory liabilities	4,789		3,698		644		160		237		31		140		25
Less: current portion	602		329		127		50		79		11		43		25
Total non-current regulatory liabilities	$	4,187	$	3,369	$	517	$	110	$	158	$	20	$	97	$	—

______

(a)

As of March 31, 2017 and December 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $1,087 million established at the date of the PHI Merger related to unrecognized costs that are probable of regulatory recovery. The regulatory assets are amortized over periods from 3 to 15 years, depending on the underlying component. Pepco, DPL and ACE are currently recovering these costs through base rates. Pepco, DPL and ACE are not earning a return on the recovery of these costs in base rates.

(b)

As of March 31, 2017, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $22 million, $39 million, $31 million, $21 million and $20 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2016, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $22 million, $38 million, $31 million, $20 million and $19 million for ComEd, BGE, Pepco, DPL and ACE, respectively.

(c)

As of March 31, 2017, ComEd’s regulatory asset of $211 million was comprised of $158 million for the 2015 - 2017 annual reconciliations and $53 million related to significant one-time events including $17 million of deferred storm costs, $10 million of Constellation and PHI merger and integration related costs and $26 million of smart meter related costs. As of December 31, 2016, ComEd’s regulatory asset of $188 million was comprised of $134 million for the 2015 and 2016 annual reconciliations and $54 million related to significant one-time events, including $20 million of deferred storm costs and $11 million of Constellation and PHI merger and integration related costs, and $23 million of smart meter related costs. ComEd's 2015 annual reconciliation regulatory asset included a reduction of $8 million related to a ComEd-proposed refund to customers for the impact of changing its OSHA recordable rate for 2014 and 2015. See Note 4— Merger, Acquisitions, and Dispositions of the Exelon 2016 Form 10-K for further information.

(d)

As of March 31, 2017, ComEd’s regulatory asset of $18 million included $10 million associated with transmission costs recoverable through its FERC approved formula rate and $8 million of Constellation merger and integration costs to be recovered upon FERC approval. As of March 31, 2017, ComEd’s regulatory liability of $38 million included $6 million related to over-recovered energy costs and $32 million associated with revenues received for renewable energy requirements. As of December 31, 2016, ComEd’s regulatory asset of $23 million included $15 million associated with transmission costs recoverable through its FERC approved formula rate and $8 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2016, ComEd’s regulatory liability of $60 million included $30 million related to over-recovered energy costs and $30 million associated with revenues received for renewable energy requirements.

(e)

As of March 31, 2017, PECO's regulatory liability of $66 million included $41 million related to over-recovered costs under the DSP program, $13 million related to the over-recovered natural gas costs under the PGC, $10 million related to over-recovered non-bypassable transmission service charges and $2 million related to over-recovered electric transmission costs. As of December 31, 2016, PECO's regulatory liability of $56 million included $34 million related to over-recovered costs under the DSP program, $10 million related to over-recovered non-bypassable transmission service charges, $8 million related to the over-recovered natural gas costs under the PGC and $4 million related to the over-recovered electric transmission costs.

(f)

As of March 31, 2017, BGE's regulatory asset of $19 million included $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $13 million related to under-recovered electric energy costs, and $3 million of abandonment costs to be recovered upon FERC approval. As of March 31, 2017, BGE's regulatory liability consisted of $2 million related to over-recovered natural gas costs. As of December 31, 2016, BGE’s regulatory asset of $38 million included $4 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $28 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $3 million of under-recovered natural gas costs.

(g)

As of March 31, 2017, Pepco's regulatory asset of $6 million included $2 million of transmission costs recoverable through its FERC approved formula rate and $4 million of under-recovered electric energy costs. As of March 31, 2017, Pepco's regulatory liability of $7 million included $2 million of over-recovered transmission costs and $5 million of over-recovered electric energy costs. As of December 31, 2016, Pepco's regulatory asset of $6 million related to under-recovered electric energy costs. As of December 31, 2016, Pepco's regulatory liability of $8 million included $5 million of over-recovered transmission costs and $3 million of over-recovered electric energy costs.

(h)

As of March 31, 2017, DPL's regulatory asset of $5 million related to under-recovered electric energy costs. As of March 31, 2017, DPL's regulatory liability of $12 million included $9 million of over-recovered electric energy costs, $1 million of over-recovered transmission costs, and $2 million of over-recovered gas cost. As of December 31, 2016, DPL's regulatory asset of $5 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $4 million of under-recovered electric energy costs. As of December 31, 2016, DPL's regulatory liability of $5 million included $2 million of over-recovered electric energy costs and $3 million of over-recovered transmission costs.

(i)

As of March 31, 2017, ACE's regulatory asset of $23 million included $10 million of transmission costs recoverable through its FERC approved formula rate and $13 million of under-recovered electric energy costs. As of March 31, 2017, ACE's regulatory liability of $8 million included $2 million of over-recovered transmission costs and $6 million of over-recovered electric energy costs. As of December 31, 2016, ACE's regulatory asset of $17 million included $6 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2016, ACE's regulatory liability of $5 million included $4 million of over-recovered transmission costs and $1 million of over-recovered electric energy costs.


(j)	As of March 31, 2017, BGE's regulatory asset of $8 million included $6 million of previously incurred PHI acquisition costs as authorized by the June 2016 rate case order.

(k)

As of March 31, 2017 and December 31, 2016, Pepco’s regulatory asset of $11 million represents previously incurred PHI acquisition costs authorized for recovery by the November 2016 Maryland distribution rate case order. As of March 31, 2017, DPL’s regulatory asset of $13 million represents previously incurred PHI acquisition costs, including $5 million authorized for recovery by the February 2017 Maryland distribution rate case order and $8 million expected to be recovered in electric and gas distribution rates in the Delaware service territory. As of December 31, 2016, DPL's regulatory asset of $4 million represents previously incurred PHI acquisition costs expected to be recovered in distribution rates in the Maryland service territory.

(l)

Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of March 31, 2017, BGE had a regulatory asset of $25 million related to under-recovered electric revenue decoupling and $6 million related to under-recovered natural gas revenue decoupling. As of December 31, 2016, BGE had a regulatory asset of $2 million related to under-recovered natural gas revenue decoupling and $1 million related to under-recovered electric revenue decoupling.

Capitalized Ratemaking Amounts Not Recognized (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

The following table illustrates our authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes on our Consolidated Balance Sheets. These amounts will be recognized as revenues in our 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
March 31, 2017	$	71	$	5	$	—	$	56	$	10	$	6	$	4	$	—

	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(b)		DPL^(b)		ACE
December 31, 2016	$	72	$	5	$	—	$	57	$	10	$	6	$	4	$	—

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(a)	Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its under-recovered distribution services costs regulatory assets.


(b)	BGE's authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment on its AMI Programs.


(c)	Pepco's and DPL's authorized amounts capitalized for ratemaking purposes related 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.

Purchase of Receivables Programs (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

ComEd, PECO, BGE, Pepco, DPL and ACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from retail electric and natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of March 31, 2017 and December 31, 2016.



													Successor
As of March 31, 2017	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables^(b)	$	305		$	85		$	72		$	59		$	89		$	58		$	10		$	21
Allowance for uncollectible accounts^(a)	(36		)	(14		)	(7		)	(4		)	(11		)	(6		)	(2		)	(3		)
Purchased receivables, net	$	269		$	71		$	65		$	55		$	78		$	52		$	8		$	18



													Successor
As of December 31, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables^(b)	$	313		$	87		$	72		$	59		$	95		$	63		$	10		$	22
Allowance for uncollectible accounts^(a)	(37		)	(14		)	(6		)	(4		)	(13		)	(7		)	(2		)	(4		)
Purchased receivables, net	$	276		$	73		$	66		$	55		$	82		$	56		$	8		$	18

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(a)	For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff.

(b)

Pepco's electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 2% depending on customer class, and Pepco's electric POR program in the District of Columbia included a discount on purchased receivables ranging from 0% to 6% depending on customer class. DPL's electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 1% depending on customer class.