81
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
September 30, 2017 | $ | 738 |
| | $ | 468 |
| | $ | 2 |
| | $ | — |
| | $ | 120 |
| | $ | 120 |
| | $ | 59 |
| | $ | 21 |
| | $ | 8 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
December 31, 2016 | $ | 916 |
| | $ | 490 |
| | $ | (12 | ) | | $ | — |
| | $ | 120 |
| | $ | 172 |
| | $ | 80 |
| | $ | 37 |
| | $ | 22 |
|
Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in 2016. In the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Fair Value of Financial Assets and Liabilities
first quarter 2017, asReconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a part of its examination of Exelon’s return,recurring basis during the IRS National Office issued guidance concurring with Exelon’s position thatthree months ended March 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd | | PHI and Pepco | | |
Three Months Ended March 31, 2023 | Total | | Mark-to-Market Derivatives | | Life Insurance Contracts | | |
Balance as of December 31, 2022 | $ | (44) | | | $ | (84) | | | $ | 40 | | | |
Total realized / unrealized gains | | | | | | | |
Included in net income(a) | 1 | | | — | | | 1 | | | |
| | | | | | | |
| | | | | | | |
Included in regulatory assets/liabilities | (14) | | | (14) | | (b) | — | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Balance as of March 31, 2023 | $ | (57) | | | $ | (98) | | (c) | $ | 41 | | | |
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2023 | $ | 1 | | | $ | — | | | $ | 1 | | | |
| | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd | | PHI and Pepco | | |
Three Months Ended March 31, 2022 | Total | | Mark-to-Market Derivatives | | Life Insurance Contracts | | |
Balance as of December 31, 2021 | $ | (182) | | | $ | (219) | | | $ | 35 | | | |
Total realized / unrealized gains | | | | | | | |
Included in net income(a) | 1 | | | — | | | 1 | | | |
| | | | | | | |
| | | | | | | |
Included in regulatory assets | 75 | | | 75 | | (b) | — | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Transfers out of Level 3 | (1) | | | — | | | — | | | |
Balance as of March 31, 2022 | $ | (107) | | | $ | (144) | | | $ | 36 | | | |
The amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities as of March 31, 2022 | $ | 1 | | | $ | — | | | $ | 1 | | | |
__________(a)Classified in Operating and maintenance expense in the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively, as of September 30, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and correspondingIncome.
(b)Includes $25 million of decreases in their effective tax rates.
Exelon reduced the liability relatedfair value and an increase for realized gains due to the uncertain tax positionsettlements of $11 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the like-kind exchangethree months ended March 31, 2023. Includes $69 million of increases in fair value and an increase for realized losses due to settlements of $6 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2022.
(c)The balance consists of a current and noncurrent liability of $22 million and $76 million, respectively, as of March 31, 2023.
Valuation Techniques Used to Determine Fair Value
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the second quartertables below are in accordance with the policies discussed in Note 17 — Fair Value of 2017. Please see the Other Income Tax Matters section below for additional details related to the like-kind exchange adjustments made in the second quarter of 2017.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Like-Kind Exchange
As of September 30, 2017, ExelonFinancial Assets and ComEd have approximately $39 million and $2 million, respectively, of unrecognized federal and state income tax benefits that could significantly decrease within the 12 months after the reporting date due to a final resolutionLiabilities of the like-kind exchange litigation described below. The recognition of these unrecognized tax benefits would decrease Exelon and ComEd's effective tax rate.2022 Form 10-K.
Settlement of Income Tax Positions
As of September 30, 2017, Exelon, Generation, BGE, PHI, Pepco, DPL, and ACE have approximately $676 million, $469 million, $120 million, $88 million, $59 million, $21 million, and $8 million of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $462 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, DPL, ACE, and a portion of Pepco, if recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
Like-Kind Exchange (Exelon and ComEd)
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities.
The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. Exelon was unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS asserted that the Exelon purchase and leaseback transaction was substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities did not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS also asserted a penalty of approximately $90 million for a substantial understatement of tax.
On September 30, 2013, the IRS issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court (Tax Court) and the trial took place in August of 2015. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue.
On September 19, 2016, the Tax Court rejected Exelon’s position in the case and ruled that Exelon was not entitled to defer gain on the transaction. In addition, contrary to Exelon’s evaluation that the penalty was unwarranted, the Tax Court ruled that Exelon is liable for the penalty and interest due on the asserted penalty. In June of 2017, the IRS finalized its computation of tax, penalties and interest owed by Exelon pursuant to the Tax Court’s decision. In September of 2017, Exelon appealed this decision to the U.S. Court of Appeals for the Seventh Circuit.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Fair Value of Financial Assets and Liabilities
InMark-to-Market Derivatives (Exelon and ComEd)
The table below discloses the first quarter of 2013, Exelon concluded that it was no longer more likely than not that the like-kind exchange position would be sustained and recorded charges to earnings representing the amount of interest expense (after-tax) and incremental state income tax expense that would be payable in the event Exelon is unsuccessful in litigation. Exelon agreed to hold ComEd harmless from any unfavorable impacts on ComEd’s equity of the after-tax interest and penalty amounts.
Priorsignificant unobservable inputs to the Tax Court’s decision, however, Exelon did not believe it was likely a penalty would be assessed based on applicable case law and the facts of the transaction. As a result, no charge had been recorded for the penalty or for after-tax interest on the penalty. While it has strong arguments on appeal with respect to both the merits and the penalty, Exelon has determined that, pursuant to accounting standards, it is no longer more likely than not to avoid ultimate imposition of the penalty. As a result, in the third quarter of 2016, Exelon and ComEd recorded a charge to earnings of approximately $106 million and $86 million, respectively, of penalty and approximately $94 million and $64 million, respectively, of after-tax interest. Exelon and ComEd recorded the penalty and pre-tax interest due on the asserted penalty to Other, net and Interest expense, net, respectively, on their Consolidated Statements of Operations. Consistent with Exelon’s agreement to continue to hold ComEd harmless from any unfavorable impact on its equity from the like-kind exchange position, ComEd recorded on its Consolidated Balance Sheets as of September 30, 2016, an additional $150 million receivable and non-cash equity contributions from Exelon.
As a result of the IRS’s finalization of its computation in the second quarter 2017, Exelon recorded a benefit to earnings of approximately $26 million, consisting of an income tax benefit of $50 million and a reduction of penalties of $2 million, partially offset by after-tax interest expense of $26 million, while ComEd recorded a charge to earnings of approximately $23 million, consisting of income tax expense of $15 million and after-tax interest expense of $8 million.
In the second quarter of 2017, Exelon amended its agreement with ComEd to also hold ComEd harmless for the unfavorable impacts on its equity from the additional income tax amounts owed by ComEd as a result of the IRS’s finalization of its computation related to the like-kind exchange position. Accordingly, in the second quarter of 2017, ComEd recorded an additional receivable and non-cash equity contribution from Exelon for the total $23 million. As of June 30, 2017, ComEd had a total receivable from Exelon pursuant to the hold harmless agreement of $369 million, which was included in Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet.
Exelon expects to pay the tax, penalties and interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd, in the fourth quarter of 2017. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position. Following a final appellate decision, which is expected in 2018, Exelon expects to receive approximately $60 million related to final interest computations.
Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. Any remaining amounts due to the IRS will be paid by Exelon in the fourth quarter of 2017. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. The deposit is reflected as a current asset and the related liabilities for the tax, penalty, and interest are included on Exelon’s balance sheet as current obligations. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. No recovery will be sought from ComEd customers for any interest, penalty, or additional income tax payment amounts resulting from the like-kind exchange tax position.
As previously disclosed, in the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. In the first quarter of 2016, Exelon terminated its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million.
Long-Term Marginal State Income Tax Rate (Exelon, Generation, ComEd, PHI and Pepco)
Exelon, Generation and PHI periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon, Generation and PHI to update their long-term state tax apportionment include significant changes in tax law
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
and/or significant operational changes. Exelon's, PHI's and Pepco's long-term marginal state income tax rate were revised in the first quarter of 2017 as a result of a statutory rate change in Washington, D.C. As a result, Exelon, PHI and Pepco recorded a one-time decrease to Deferred income tax liability of $28 million, $8 million, and $8 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, Exelon, PHI and Pepco recorded a corresponding regulatory liability of $8 million, in the Consolidated Balance Sheets. In addition, Exelon recorded a decrease to Income tax expense of $20 million, net of federal taxes, in the Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2017.
In the third quarter of 2017, Exelon reviewed and updated its marginal state income tax rates based on 2016 state apportionment rates. In addition, Exelon, Generation and ComEd recorded the impacts of Illinois’ statutory rate change, which increased the total corporate income tax rate from 7.75% to 9.5% effective July 1, 2017. As a result of the rate changes, in the third quarter of 2017, Exelon, Generation and ComEd recorded a one-time increase to Deferred income taxes of approximately $250 million, $20 million and $270 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, each of Exelon and ComEd recorded a corresponding regulatory asset of $272 million. Further, Exelon recorded a decrease to Income tax expense of approximately $20 million and Generation recorded an increase to Income tax expense of approximately $20 million (each net of federal taxes) in their Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2017. The Illinois statutory rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future results of operations.
13. Nuclear Decommissioning (Exelon and Generation)
Nuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2016 to September 30, 2017:
|
| | | |
Nuclear decommissioning ARO at December 31, 2016(a) | $ | 8,734 |
|
Acquisition of FitzPatrick | 444 |
|
Accretion expense | 342 |
|
Net decrease due to changes in, and timing of, estimated cash flows | (148 | ) |
Costs incurred to decommission retired plants | (6 | ) |
Nuclear decommissioning ARO at September 30, 2017(a) | $ | 9,366 |
|
_________
| |
(a) | Includes $12 million and $10 million for the current portion of the ARO at September 30, 2017 and December 31, 2016, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. |
During the nine months ended September 30, 2017, Generation’s nuclear ARO increased by approximately $632 million. The increase primarily reflects the net impacts of the acquisition of FitzPatrick, the announced early retirement of TMI, year-to-date accretion of the ARO liability due to the passage of time and ARO updates completed during 2017 to reflect changes in amounts and timing of estimated decommissioning cash flows.
In the first quarter of 2017, a preliminary estimate of $417 million was recorded for the fair value of FitzPatrick’s ARO. In the third quarter of 2017, an adjustment was recorded to increase the FitzPatrick ARO valuation by $27 million to $444 million to reflect updated cost estimate inputs from a third-party engineering firm. For additional details on the acquisition of FitzPatrick, see Note 4 - Mergers, Acquisitions and Dispositions.
The net $148 million decrease due to changes in, and timing of, estimated cash flows was driven by multiple adjustments throughout the period, some with offsetting impacts. These adjustments include a $180 million decrease
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
for refinements in estimated fleet wide labor costs expected to be incurred for certain on-site personnel during decommissioning as well as decreases resulting from updates to the cost studies of Clinton and Quad Cities. These decreases were partially offset by a $138 million increase in TMI's ARO liability associated with the May 30, 2017 announcement to early retire the unit on September 30, 2019. The increase in the ARO liability for TMI incorporates the early shutdown date, increases the probabilities of longer term decommissioning scenarios, and reflects an increase in the estimated costs to decommission based on an updated decommissioning cost study. Refer to Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.
Nuclear Decommissioning Trust Fund Investments
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not beforward curve used to fund the decommissioning obligations of any other unit.value mark-to-market derivatives.
The NDT funds associated with Generation’s nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment (NDCA) with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the current approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates will be effective January 1, 2018. See Note 16 - Asset Retirement Obligations of Exelon's 2016 Form 10-K, for information regarding the amount collected from PECO ratepayers for decommissioning costs. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Type of trade | | Fair Value as of March 31, 2023 | | Fair Value as of December 31, 2022 | | Valuation Technique | | Unobservable Input | | 2023 Range & Arithmetic Average | | 2022 Range & Arithmetic Average |
Mark-to-market derivatives | | $ | (98) | | | $ | (84) | | | Discounted Cash Flow | | Forward power price(a) | | $22.49 | - | $83.26 | $47.69 | | $34.78 | - | $75.71 | $48.44 |
Exelon and Generation had NDT fund investments totaling $12,966 million and $11,061 million at September 30, 2017 and December 31, 2016, respectively. The increase is primarily driven by improved market performance and the acquisition of FitzPatrick.________
The following table provides unrealized gains on NDT funds for the three and nine months ended September 30, 2017 and 2016:
|
| | | | | | | | | | | | | | | |
| Exelon and Generation | | Exelon and Generation |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 44 |
| | $ | 155 |
| | $ | 253 |
| | $ | 286 |
|
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c) | 111 |
| | 116 |
| | 347 |
| | 216 |
|
_________
| |
(a) | Net unrealized gains related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets. |
| |
(b) | Excludes $4 million and $5 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 2017 and 2016 respectively. Excludes $5 million and $2 million of net unrealized losses related to the Zion Station pledged assets for the nine months ended September 30, 2017 and 2016, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities and Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets in 2017 and 2016, respectively. |
| |
(c) | Net unrealized gains related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. |
Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Refer to Note 3 — Regulatory Matters and Note 27 — Related Party Transactions of the Exelon 2016 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning
On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for completing certain decommissioning activities at Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 16 — Asset Retirement Obligations of the Exelon 2016 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, are recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $112 million which is included within the nuclear decommissioning ARO at September 30, 2017. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at September 30, 2017 and December 31, 2016:
|
| | | | | | | |
| Exelon and Generation |
| September 30, 2017 | | December 31, 2016 |
Carrying value of Zion Station pledged assets | $ | 57 |
| | $ | 113 |
|
Payable to Zion Solutions(a) | 53 |
| | 104 |
|
Current portion of payable to Zion Solutions(b) | 53 |
| | 90 |
|
Cumulative withdrawals by Zion Solutions to pay decommissioning costs(c) | 928 |
| | 878 |
|
_________
| |
(a) | Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. |
| |
(b) | Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets. |
| |
(c) | Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings. |
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.
Generation filed its biennial decommissioning funding status report with the NRC on March 30, 2017 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions (see Zion Station Decommissioning above). The status report demonstrated adequate decommissioning funding assurance for all units except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers has been adjusted in the March 31, 2017 filing to the PAPUC which was approved on August 8, 2017 and will be effective January 1, 2018.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation will file its next decommissioning funding status report with the NRC by March 31, 2018 for shutdown reactors and reactors within five years of shutdown. This report will reflect the status of decommissioning funding assurance as of December 31, 2017 and will include the impact of the announced early retirement of TMI. A shortfall could necessitate that Exelon post a parental guarantee for Generation’s share of the funding assurance. However, the amount of any required guarantee will ultimately depend on the decommissioning approach adopted at TMI, the associated level of costs, and the decommissioning trust fund investment performance going forward.
14. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all employees. Effective March 23, 2016, Exelon became the sponsor of all of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets. As a result, PHI's benefit plan net obligation and related regulatory assets were transferred to Exelon.
During the first quarter of 2017, in connection with the acquisition of Fitzpatrick, Exelon established a new qualified pension plan and a new OPEB plan, and recorded a provisional obligation for Fitzpatrick employees based on information available at the merger date of $38 million and $11 million, respectively. As permitted by business combinations accounting guidance, during the third quarter of 2017, Exelon updated those obligations based on a final valuation for Fitzpatrick employees as of the merger date of March 31, 2017. The updated obligations for pension and OPEB were $16 million and $17 million, respectively. Refer to Note 4 - Mergers, Acquisitions and Dispositions for additional discussion of the acquisition of FitzPatrick.
Defined Benefit Pension and Other Postretirement Benefits
During the first quarter of 2017, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2017. This valuation resulted in an(a)An increase to the pension obligation of $92 million and anforward power price would increase to the other postretirement benefit obligation of $57 million. Additionally, accumulated other comprehensive loss increased by approximately $59 million (after tax), regulatory assets increased by approximately $57 million and regulatory liabilities increased by approximately $4 million.fair value.
The majority of the 2017 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.04%. The majority of the 2017 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.58% for funded plans and a discount rate of 4.04%.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2017 and 2016 and PHI's net periodic benefit costs, prior to capitalization, for the predecessor period of January 1, 2016 to March 23, 2016.
|
| | | | | | | | | | | | | | | |
| Pension Benefits Three Months Ended September 30, | | Other Postretirement Benefits Three Months Ended September 30, |
| 2017(a) | | 2016(b) | | 2017(a) | | 2016(b) |
Components of net periodic benefit cost: | | | | | | | |
Service cost | $ | 98 |
| | $ | 92 |
| | $ | 26 |
| | $ | 27 |
|
Interest cost | 211 |
| | 215 |
| | 45 |
| | 47 |
|
Expected return on assets | (300 | ) | | (293 | ) | | (39 | ) | | (42 | ) |
Amortization of: | | | | | | | |
Prior service (benefit) cost | (1 | ) | | 3 |
| | (47 | ) | | (48 | ) |
Actuarial loss | 152 |
| | 142 |
| | 15 |
| | 18 |
|
Settlement charges | 1 |
| | — |
| | — |
| | — |
|
Net periodic benefit cost | $ | 161 |
| | $ | 159 |
| | $ | — |
| | $ | 2 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
| | | | | | | | | | | | | | | |
| Pension Benefits Nine Months Ended September 30, | | Other Postretirement Benefits Nine Months Ended September 30, |
| 2017(a) | | 2016(b) | | 2017(a) | | 2016(b) |
Components of net periodic benefit cost: |
|
| |
|
| |
|
| |
|
|
Service cost | $ | 290 |
| | $ | 262 |
| | $ | 79 |
| | $ | 80 |
|
Interest cost | 632 |
| | 616 |
| | 136 |
| | 138 |
|
Expected return on assets | (898 | ) | | (847 | ) | | (121 | ) | | (121 | ) |
Amortization of: | | | | | | | |
Prior service cost (benefit) | — |
| | 10 |
| | (140 | ) | | (138 | ) |
Actuarial loss | 455 |
| | 411 |
| | 46 |
| | 47 |
|
Settlement charges | 3 |
| | — |
| | — |
| | — |
|
Net periodic benefit cost | $ | 482 |
|
| $ | 452 |
|
| $ | — |
|
| $ | 6 |
|
_________
| |
(a) | FitzPatrick net benefit costs are included for the period after acquisition. |
| |
(b) | PHI net periodic benefit costs for the period prior to the merger are not included in the table above. |
|
| | | | | | | |
| Predecessor |
| PHI |
| Pension Benefits | | Other Postretirement Benefits |
| January 1, 2016 to March 23, 2016 | | January 1, 2016 to March 23, 2016 |
Components of net periodic benefit cost: | | | |
Service cost | $ | 12 |
| | $ | 1 |
|
Interest cost | 26 |
| | 6 |
|
Expected return on assets | (30 | ) | | (5 | ) |
Amortization of: | | | |
Prior service cost (benefit) | — |
| | (3 | ) |
Actuarial loss | 14 |
| | 2 |
|
Net periodic benefit cost | $ | 22 |
| | $ | 1 |
|
The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's, ACE's, BSC's and PHISCO's allocated portion of the pension and postretirement benefit plan costs, which were included in Property, plant and equipment within the respective Consolidated Balance Sheets and Operating and maintenance expense within the Consolidated Statement of Operations and Comprehensive Income during the three and nine months ended September 30, 2017 and 2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016, respectively.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Pension and Other Postretirement Benefit Costs | 2017 | | 2016 | | 2017 | | 2016 |
Exelon | $ | 161 |
| | $ | 161 |
| | $ | 482 |
| | $ | 458 |
|
Generation(a) | 57 |
| | 54 |
| | 170 |
| | 163 |
|
ComEd | 44 |
| | 41 |
| | 131 |
| | 124 |
|
PECO | 7 |
| | 8 |
| | 21 |
| | 25 |
|
BGE | 16 |
| | 17 |
| | 48 |
| | 51 |
|
BSC(b) | 13 |
| | 13 |
| | 40 |
| | 37 |
|
Pepco(c) | 6 |
| | 8 |
| | 19 |
| | 24 |
|
DPL(c) | 3 |
| | 4 |
| | 10 |
| | 13 |
|
ACE(c) | 3 |
| | 4 |
| | 10 |
| | 11 |
|
PHISCO(c)(d) | 12 |
| | 12 |
| | 33 |
| | 33 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
Pension and Other Postretirement Benefit Costs | Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 | | Nine Months Ended September 30, 2017 | | March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | $ | 24 |
| | $ | 28 |
| | $ | 72 |
| | $ | 58 |
| | | $ | 23 |
|
_________
| |
(a) | FitzPatrick net benefit costs are included for the period after acquisition. |
| |
(b) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above. |
| |
(c) | Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the nine months ended September 30, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016. |
| |
(d) | These amounts represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL, or ACE amounts above. |
Defined Contribution Savings Plans
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and nine months ended September 30, 2017 and 2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016, respectively.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Savings Plan Matching Contributions | 2017 | | 2016 | | 2017 | | 2016 |
Exelon | $ | 34 |
|
| $ | 51 |
|
| $ | 97 |
|
| $ | 107 |
|
Generation | 14 |
| | 31 |
| | 42 |
| | 56 |
|
ComEd | 9 |
| | 10 |
| | 24 |
| | 23 |
|
PECO | 3 |
| | 3 |
| | 7 |
| | 7 |
|
BGE | 3 |
| | 2 |
| | 7 |
| | 5 |
|
BSC(a) | 2 |
| | 2 |
| | 7 |
| | 9 |
|
Pepco(b) | 1 |
| | — |
| | 3 |
| | 2 |
|
DPL(b) | 1 |
| | 1 |
| | 2 |
| | 2 |
|
ACE | — |
| | — |
| | 1 |
| | 1 |
|
PHISCO(b)(c) | 1 |
| | 2 |
| | 4 |
| | 5 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
Savings Plan Matching Contributions | Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 | | Nine Months Ended September 30, 2017 | | March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | $ | 3 |
| | $ | 3 |
| | $ | 10 |
| | $ | 7 |
| | | $ | 3 |
|
_________
| |
(a) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above. |
| |
(b) | Pepco's, DPL's and PHISCO's matching contributions for the nine months ended September 30, 2016 include $1 million, $1 million, and $1 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016, which is not included in Exelon’s matching contributions for the nine months ended September 30, 2016. |
| |
(c) | These amounts represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL, or ACE amounts above. |
15. Severance (All Registrants)
The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.
Ongoing Severance Plans
The Registrants provide severance and health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees in the normal course of business. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.
For the three and nine months ended September 30, 2017 and 2016, Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Successor | | | | | | |
| Exelon | | Generation(a) | | ComEd(a) | | PHI | | Pepco(a) | | DPL(a) | | ACE(a) |
Three Months Ended | | | | | | | | | | | | | |
September 30, 2017 | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
September 30, 2016 | 8 |
| | 7 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | |
Nine Months Ended | | | | | | | | | | | | | |
September 30, 2017 | $ | 10 |
| | $ | 4 |
| | $ | 2 |
| | $ | 4 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
September 30, 2016 | 12 |
| | 10 |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
_________
| |
(a) | The amounts above for Generation include $2 million for amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 and $1 million and $2 million for the three and nine months ended September 30, 2016, respectively. The amounts above for ComEd include $1 million for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2016. The amounts above for PHI include less than $1 million and $1 million billed by BSC through intercompany allocations for the three and nine months ended September 30, 2017, respectively, and $1 million for the three and nine months ended September 30, 2016. Amounts billed by PHISCO to Pepco were $1 million and $2 million for the three and nine months ended September 30, 2017, respectively. Amounts billed by PHISCO to DPL and ACE were $1 million, each, for the nine months ended September 30, 2017. Pepco, DPL and ACE did not have any ongoing severance plans for the three and nine months ended September 30, 2016. |
Cost Management Program-Related Severance
In August 2015, Exelon announced a cost management program focused on cost savings at BSC and Generation, including the elimination of approximately 500 positions. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity. Exelon expects that approximately 250 corporate support positions in BSC and approximately 250 positions located throughout Generation will be eliminated.
For the three and nine months ended September 30, 2017 and 2016, the Registrants recorded the following severance costs related to the cost management program within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:
|
| | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE |
Three Months Ended | | | | | | | | | |
September 30, 2017(a) | $ | 7 |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | — |
|
September 30, 2016(b) | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| | | | | | | | | |
Nine Months Ended | | | | | | | | | |
September 30, 2017(a) | $ | 6 |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
|
September 30, 2016(b) | 18 |
| | 13 |
| | 3 |
| | 1 |
| | 1 |
|
_________
| |
(a) | Amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 were immaterial. |
| |
(b) | The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2016. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Early Plant Retirement-Related Severance (Exelon and Generation)
As a result of the Three Mile Island plant retirement decision, Exelon and Generation will incur certain employee-related costs, including severance benefit costs. Severance costs will be provided to management employees that are eligible under Exelon’s severance policy, to the extent that those employees are not redeployed to other locations. In June 2017, Exelon and Generation recognized severance costs of $17 million related to expected management employee severances resulting from the plant retirements within Operating and maintenance expense in their Consolidated Statements of Operation and Comprehensive Income. Approximately half of the employees at this location fall under a collective bargaining union agreement and are not eligible for severance benefits under an existing plan. The union and Exelon will negotiate terms of any severance benefits. If severance benefits are successfully negotiated, the amounts will be accrued as a one-time employee termination benefit once the established plan is communicated to employees. The final amount of the severance cost will ultimately depend on the specific employees severed. See Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.
Severance Costs Related to the PHI Merger
Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. Cash payments under the plan began in May 2016 and will continue through 2020.
For the three and nine months ended September 30, 2017 and the three months ended September 30, 2016, the PHI Merger severance costs were immaterial. For the nine months ended September 30, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Nine Months Ended September 30, 2016 | | | | | | | | | | | | | | | | | |
Severance costs(a) | $ | 55 |
| | $ | 9 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 42 |
| | $ | 20 |
| | $ | 12 |
| | $ | 10 |
|
_________
| |
(a) | The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $8 million, $2 million, $1 million, $1 million, $19 million, $11 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the nine months ended September 30, 2016. |
PHI, Pepco, DPL and ACE record regulatory assets for merger related integration costs which include a portion of the severance costs in the table above related to the PHI Merger. These regulatory assets are either currently being recovered in rates or are deemed probable of recovery in future rates. See Note 5 - Regulatory Matters for further information.
Severance Liability
Amounts included in the table below represent the severance liability recorded for the severance plans above for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
Severance Liability | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Balance at December 31, 2016 | $ | 88 |
| | $ | 36 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Severance charges(a) | 33 |
| | 25 |
| | 1 |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
Payments | (24 | ) | | (7 | ) | | (1 | ) | | — |
| | — |
| | (11 | ) | | — |
| | — |
| | — |
|
Balance at September 30, 2017 | $ | 97 |
| | $ | 54 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | — |
|
_________
| |
(a) | Includes salary continuance and health and welfare severance benefits. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
16. Changes in Accumulated Other Comprehensive Income (Exelon, Generation, PECO and PHI)
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the nine months ended September 30, 2017 and 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2017 | Gains and (losses) on Cash Flow Hedges | | Unrealized Gains and (losses) on Marketable Securities | | Pension and Non-Pension Postretirement Benefit Plan Items | | Foreign Currency Items | | AOCI of Equity Investments | | Total |
Exelon(a) | | | | | | | | | | | |
Beginning balance | $ | (17 | ) | | $ | 4 |
| | $ | (2,610 | ) | | $ | (30 | ) | | $ | (7 | ) | | $ | (2,660 | ) |
OCI before reclassifications | 2 |
| | 2 |
| | (55 | ) | | 7 |
| | 7 |
| | (37 | ) |
Amounts reclassified from AOCI(b) | 3 |
| | — |
| | 105 |
| | — |
| | — |
| | 108 |
|
Net current-period OCI | 5 |
| | 2 |
| | 50 |
| | 7 |
| | 7 |
| | 71 |
|
Ending balance | $ | (12 | ) | | $ | 6 |
| | $ | (2,560 | ) | | $ | (23 | ) | | $ | — |
| | $ | (2,589 | ) |
Generation(a) | | | | | | | | | | |
|
|
Beginning balance | $ | (19 | ) | | $ | 2 |
| | $ | — |
| | $ | (30 | ) | | $ | (7 | ) | | $ | (54 | ) |
OCI before reclassifications | 2 |
| | — |
| | — |
| | 7 |
| | 6 |
| | 15 |
|
Amounts reclassified from AOCI(b) | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
Net current-period OCI | 5 |
| | — |
| | — |
| | 7 |
| | 6 |
| | 18 |
|
Ending balance | $ | (14 | ) | | $ | 2 |
| | $ | — |
| | $ | (23 | ) | | $ | (1 | ) | | $ | (36 | ) |
PECO(a) | | | | | | | | | | |
|
Beginning balance | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
OCI before reclassifications | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts reclassified from AOCI(b) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net current-period OCI | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Ending balance | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2016 | Gains and (losses) on Cash Flow Hedges | | Unrealized Gains and (losses) on Marketable Securities | | Pension and Non-Pension Postretirement Benefit Plan Items | | Foreign Currency Items | | AOCI of Equity Investments | | Total |
Exelon(a) | | | | | | | | | | | |
Beginning balance | $ | (19 | ) | | $ | 3 |
| | $ | (2,565 | ) | | $ | (40 | ) | | $ | (3 | ) | | $ | (2,624 | ) |
OCI before reclassifications | (9 | ) | | — |
| | (2 | ) | | 3 |
| | (5 | ) | | (13 | ) |
Amounts reclassified from AOCI(b) | 5 |
| | — |
| | 104 |
| | 5 |
| | — |
| | 114 |
|
Net current-period OCI | (4 | ) | | — |
| | 102 |
| | 8 |
| | (5 | ) | | 101 |
|
Ending balance | $ | (23 | ) | | $ | 3 |
| | $ | (2,463 | ) | | $ | (32 | ) | | $ | (8 | ) | | $ | (2,523 | ) |
Generation(a) | | | | | | | | | | |
|
Beginning balance | $ | (21 | ) | | $ | 1 |
| | $ | — |
| | $ | (40 | ) | | $ | (3 | ) | | $ | (63 | ) |
OCI before reclassifications | (8 | ) | | 1 |
| | — |
| | 3 |
| | 1 |
| | (3 | ) |
Amounts reclassified from AOCI(b) | 5 |
| | — |
| | — |
| | 5 |
| | — |
| | 10 |
|
Net current-period OCI | (3 | ) | | 1 |
| | — |
| | 8 |
| | 1 |
| | 7 |
|
Ending balance | $ | (24 | ) | | $ | 2 |
| | $ | — |
| | $ | (32 | ) | | $ | (2 | ) | | $ | (56 | ) |
PECO(a) | | | | | | | | | | |
|
|
Beginning balance | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
OCI before reclassifications | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts reclassified from AOCI(b) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net current-period OCI | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Ending balance | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
PHI Predecessor(a) | | | | | | | | | | | |
Beginning balance January 1, 2016 | $ | (8 | ) | | $ | — |
| | $ | (28 | ) | | $ | — |
| | $ | — |
| | $ | (36 | ) |
OCI before reclassifications | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts reclassified from AOCI(b) | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Net current-period OCI | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Ending balance March 23, 2016(c) | $ | (8 | ) | | $ | — |
| | $ | (27 | ) | | $ | — |
| | $ | — |
| | $ | (35 | ) |
_________
| |
(a) | All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI. |
| |
(b) | See next tables for details about these reclassifications. |
| |
(c) | As a result of the PHI Merger, the PHI predecessor balances at March 23, 2016 were reduced to zero on March 24, 2016 due to purchase accounting adjustments applied to PHI. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
ComEd, PECO, BGE, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three and nine months ended September 30, 2017 and 2016. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and PHI during the three and nine months ended September 30, 2017 and 2016.
Three Months Ended September 30, 2017
|
| | | | | | | | | | |
Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | Exelon | | Generation | | |
Gains (losses) on cash flow hedges | | | | | | |
Other cash flow hedges | | $ | 2 |
| | $ | 2 |
| | Interest expense |
Total before tax | | 2 |
| | 2 |
| | |
Tax benefit | | (1 | ) | | (1 | ) | | |
Net of tax | | $ | 1 |
| | $ | 1 |
| | Comprehensive income |
| | | | | | |
Amortization of pension and other postretirement benefit plan items | | | | | | |
Prior service costs(b) | | $ | 23 |
| | $ | — |
| | |
Actuarial losses(b) | | (81 | ) | | — |
| | |
Total before tax | | (58 | ) | | — |
| | |
Tax benefit | | 23 |
| | — |
| | |
Net of tax | | $ | (35 | ) | | $ | — |
| | |
| | | | | | |
Total Reclassifications for the period | | $ | (34 | ) | | $ | 1 |
| | Comprehensive income |
Nine Months Ended September 30, 2017
|
| | | | | | | | | | |
Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | | | | | |
| | Exelon | | Generation | | |
Gains and (losses) on cash flow hedges | | | | | | |
Other cash flow hedges | | $ | (5 | ) | | $ | (5 | ) | | Interest expense |
Total before tax | | (5 | ) |
| (5 | ) |
| |
Tax benefit | | 2 |
| | 2 |
| | |
Net of tax | | $ | (3 | ) | | $ | (3 | ) | | Comprehensive income |
| | | | | | |
Amortization of pension and other postretirement benefit plan items | | | | | | |
Prior service costs(b) | | $ | 69 |
| | $ | — |
| | |
Actuarial losses(b) | | (243 | ) | | — |
| | |
Total before tax | | (174 | ) | | — |
| | |
Tax benefit | | 69 |
| | — |
| | |
Net of tax | | $ | (105 | ) | | $ | — |
| | |
| | | | | | |
Total Reclassifications | | $ | (108 | ) | | $ | (3 | ) | | Comprehensive income |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Three Months Ended September 30, 2016 |
| | | | | | | | | | |
Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | | | | | |
| | Exelon | | Generation | | |
Gains and (losses) on cash flow hedges | | | | | | |
Other cash flow hedges | | $ | (3 | ) | | $ | (3 | ) | | Interest expense |
Total before tax | | (3 | ) | | (3 | ) | | |
Tax expense | | 1 |
| | 1 |
| | |
Net of tax | | $ | (2 | ) | | $ | (2 | ) | | Comprehensive income |
| | | | | | |
Amortization of pension and other postretirement benefit plan items | | | | | | |
Prior service costs(b) | | $ | 19 |
| | $ | — |
| | |
Actuarial losses(b) | | (76 | ) | | — |
| | |
Total before tax | | (57 | ) | | — |
| | |
Tax benefit | | 22 |
| | — |
| | |
Net of tax | | $ | (35 | ) | | $ | — |
| | |
| | | | | | |
Gains and (losses) on foreign currency translation | | | | | | |
Other | | $ | (5 | ) | | $ | (5 | ) | | Other Income and (deductions) |
Total before tax | | (5 | ) | | (5 | ) | | |
Tax expense | | — |
| | — |
| | |
Net of tax | | $ | (5 | ) | | $ | (5 | ) | | Comprehensive income |
| | | | | | |
Total Reclassifications for the period | | $ | (42 | ) | | $ | (7 | ) | | Comprehensive income |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2016
|
| | | | | | | | | | | | | | |
Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | | | | | Predecessor | | |
| | Exelon | | Generation | | PHI | | |
Gains and (losses) on cash flow hedges | | | | | | | | |
Other cash flow hedges | | $ | (8 | ) | | $ | (8 | ) | | $ | — |
| | Interest expense |
Total before tax | | (8 | ) |
| (8 | ) |
| — |
| | |
Tax benefit | | 3 |
| | 3 |
| | — |
| | |
Net of tax | | $ | (5 | ) | | $ | (5 | ) | | $ | — |
| | Comprehensive income |
| | | | | | | | |
Amortization of pension and other postretirement benefit plan items | | | | | | | | |
Prior service costs(b) | | $ | 57 |
| | $ | — |
| | $ | — |
| | |
Actuarial losses(b) | | (227 | ) | | — |
| | (1 | ) | | |
Total before tax | | (170 | ) | | — |
| | (1 | ) | | |
Tax benefit | | 66 |
| | — |
| | — |
| | |
Net of tax | | $ | (104 | ) | | $ | — |
| | $ | (1 | ) | | |
| | | | | | | | |
Gains and (losses) on foreign currency translation | | | | | | | | |
Other | | $ | (5 | ) | | $ | (5 | ) | | $ | — |
| | Other income and (deductions) |
Total before tax | | (5 | ) | | (5 | ) | | — |
| | |
Tax expense | | — |
| | — |
| | — |
| | |
Net of tax | | $ | (5 | ) | | $ | (5 | ) | | $ | — |
| | |
| | | | | | | | |
Total Reclassifications | | $ | (114 | ) | | $ | (10 | ) | | $ | (1 | ) | | Comprehensive income |
_________
| |
(a) | Amounts in parenthesis represent a decrease in net income. |
| |
(b) | This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 14 — Retirement Benefits for additional details). |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three and nine months ended September 30, 2017 and 2016:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Exelon | | | | | | | |
Pension and non-pension postretirement benefit plans: | | | | | | | |
Prior service benefit reclassified to periodic benefit cost | $ | 9 |
| | $ | 7 |
| | $ | 27 |
| | $ | 22 |
|
Actuarial loss reclassified to periodic benefit cost | (32 | ) | | (29 | ) | | (96 | ) | | (88 | ) |
Pension and non-pension postretirement benefit plans valuation adjustment | — |
| | 1 |
| | 2 |
| | 1 |
|
Change in unrealized (loss)/gain on cash flow hedges | — |
| | (1 | ) | | (3 | ) | | 3 |
|
Change in unrealized (loss)/gain on equity investments | 1 |
| | — |
| | (2 | ) | | 3 |
|
Change in unrealized (loss)/gain on marketable securities | — |
| | (1 | ) | | (2 | ) | | (1 | ) |
Total | $ | (22 | ) | | $ | (23 | ) | | $ | (74 | ) | | $ | (60 | ) |
| | | | | | | |
Generation | | | | | | | |
Change in unrealized (loss)/gain on cash flow hedges | $ | — |
| | $ | (2 | ) | | $ | (3 | ) | | $ | 1 |
|
Change in unrealized (loss)/gain on equity investments | — |
| | — |
| | (2 | ) | | 3 |
|
Change in unrealized gain on marketable securities | — |
| | — |
| | (1 | ) | | — |
|
Total | $ | — |
| | $ | (2 | ) | | $ | (6 | ) | | $ | 4 |
|
|
| | | |
| Predecessor |
PHI | January 1, 2016 to March 23, 2016 |
Pension and non-pension postretirement benefit plans: | |
Actuarial loss reclassified to periodic cost | $ | — |
|
17. Earnings Per Share and Equity (Exelon)
Earnings per Share
Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, |
| Nine Months Ended September 30, |
| 2017 |
| 2016 |
| 2017 |
| 2016 |
Exelon | | | | | | | |
Net income attributable to common shareholders | $ | 824 |
| | $ | 490 |
| | $ | 1,899 |
| | $ | 930 |
|
Weighted average common shares outstanding — basic | 962 |
| | 925 |
| | 941 |
| | 924 |
|
Assumed exercise and/or distributions of stock-based awards | 3 |
| | 2 |
| | 2 |
| | 2 |
|
Weighted average common shares outstanding — diluted | 965 |
| | 927 |
| | 943 |
| | 926 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 7 million and 9 million for the three and nine months ended September 30, 2017, respectively, and 11 million and 12 million for the three and nine months ended September 30, 2016, respectively. There were no equity units related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the three and nine months ended September 30, 2017. The number of equity units related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the three and nine months ended September 30, 2016. Refer to Note 20 — Shareholders' Equity of the Exelon 2016 Form 10-K for further information regarding the equity units.
On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of approximately 33 million shares of Exelon common stock from treasury stock. The issuance of shares on June 1, 2017, triggered full dilution in the EPS calculation, which prior to settlement were included in the calculation of diluted EPS using the treasury stock method.
Prior to the June 2017 issuance Exelon had approximately 35 million shares of treasury stock with a cost of $2.3 billion. After issuance, Exelon has approximately 2 million shares of Treasury stock remaining, at a historical cost of $123 million. In 2008, Exelon management decided to defer indefinitely any share repurchases.
18.12. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 24 of the Exelon 2016 Form 10-K . See Note 4 - Mergers, Acquisitions and Dispositions for further discussion on the PHI Merger commitments.
Commitments
Constellation Merger Commitments (Exelon and Generation)
In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.
The direct investment includes the construction of a new 21-story headquarters building in Baltimore for Generation’s competitive energy business that was substantially complete in November 2016 and is now occupied by approximately 1,500 Exelon employees. Generation’s investment includes leasehold improvements that are not expected to exceed $110 million. In addition, Generation entered into a 20 year operating lease as the primary lessee of the building. Refer to Note 24 -18 — Commitments and Contingencies of the Combined Notes to2022 Form 10-K.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the Consolidated Financial StatementsPHI Merger in Delaware, New Jersey, Maryland, and the Exelon 2016 Form 10-K for additional information regarding Generation’s future minimum lease payments.
The direct investment commitment also includes $450 million to $500 million relating toDistrict of Columbia was conditioned upon Exelon and Generation’s development or assistance inPHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the development of 285-300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years. The MDPSC order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation have incurred $457 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations toacquisition date and an additional 10 MW commitment satisfiedthe total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of March 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Description | Exelon | | PHI | | Pepco | | DPL | | ACE |
Total commitments | $ | 513 | | | $ | 320 | | | $ | 120 | | | $ | 89 | | | $ | 111 | |
Remaining commitments(a) | 48 | | | 42 | | | 37 | | | 3 | | | 2 | |
| | | | | | | | | |
__________
(a)Remaining commitments extend through a liquidated damages payment made in the fourth quarter of 2016. Additionally, during the fourth quarter of 2016, given continued declines in projected2026 and include rate credits, energy efficiency programs and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment will now most likely be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, Exelon and Generation recorded a pre-tax$50 million loss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.delivery system modernization.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Equity InvestmentNote 12 — Commitments (Exelon and Generation)
As part of Generation's recent investments in technology development, Generation enters into equity purchase agreements that include commitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associated companies. As of September 30, 2017, Generation’s estimated commitments relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:
|
| | | |
| Total |
2017 (remainder of year) | $ | 12 |
|
2018 | 6 |
|
2019 | 3 |
|
Total | $ | 21 |
|
Commercial Commitments (All Registrants)
.The Registrants’ commercial commitments as of September 30, 2017,March 31, 2023, representing commitments potentially triggered by future events were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | 2028 and beyond |
Exelon | | | | | | | | | | | | | |
Letters of credit | $ | 19 | | | $ | 17 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Surety bonds(a) | 205 | | | 190 | | | 15 | | | — | | | — | | | — | | | — | |
Financing trust guarantees | 378 | | | — | | | — | | | — | | | — | | | — | | | 378 | |
Guaranteed lease residual values(b) | 29 | | | — | | | 5 | | | 6 | | | 5 | | | 4 | | | 9 | |
Total commercial commitments | $ | 631 | | | $ | 207 | | | $ | 22 | | | $ | 6 | | | $ | 5 | | | $ | 4 | | | $ | 387 | |
| | | | | | | | | | | | | |
ComEd | | | | | | | | | | | | | |
Letters of credit | $ | 12 | | | $ | 10 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Surety bonds(a) | 47 | | | 42 | | | 5 | | | — | | | — | | | — | | | — | |
Financing trust guarantees | 200 | | | — | | | — | | | — | | | — | | | — | | | 200 | |
Total commercial commitments | $ | 259 | | | $ | 52 | | | $ | 7 | | | $ | — | | | $ | — | | | $ | — | | | $ | 200 | |
| | | | | | | | | | | | | |
PECO | | | | | | | | | | | | | |
Letters of credit | $ | 1 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Surety bonds(a) | 2 | | | 1 | | | 1 | | | — | | | — | | | — | | | — | |
Financing trust guarantees | 178 | | | — | | | — | | | — | | | — | | | — | | | 178 | |
Total commercial commitments | $ | 181 | | | $ | 2 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | 178 | |
| | | | | | | | | | | | | |
BGE | | | | | | | | | | | | | |
Letters of credit | $ | 2 | | | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Surety bonds(a) | 3 | | | 2 | | | 1 | | | — | | | — | | | — | | | — | |
Total commercial commitments | $ | 5 | | | $ | 4 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | |
PHI | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Surety bonds(a) | $ | 95 | | | $ | 90 | | | $ | 5 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Guaranteed lease residual values(b) | 29 | | | — | | | 5 | | | 6 | | | 5 | | | 4 | | | 9 | |
Total commercial commitments | $ | 124 | | | $ | 90 | | | $ | 10 | | | $ | 6 | | | $ | 5 | | | $ | 4 | | | $ | 9 | |
| | | | | | | | | | | | | |
Pepco | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Surety bonds(a) | $ | 84 | | | $ | 84 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Guaranteed lease residual values(b) | 10 | | | — | | | 2 | | | 2 | | | 2 | | | 1 | | | 3 | |
Total commercial commitments | $ | 94 | | | $ | 84 | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 1 | | | $ | 3 | |
| | | | | | | | | | | | | |
DPL | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Surety bonds(a) | $ | 6 | | | $ | 2 | | | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Guaranteed lease residual values(b) | 12 | | | — | | | 2 | | | 2 | | | 2 | | | 2 | | | 4 | |
Total commercial commitments | $ | 18 | | | $ | 2 | | | $ | 6 | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 4 | |
| | | | | | | | | | | | | |
ACE | | | | | | | | | | | | | |
Surety bonds(a) | $ | 5 | | | $ | 4 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Guaranteed lease residual values(b) | 7 | | | — | | | 1 | | | 2 | | | 1 | | | 1 | | | 2 | |
Total commercial commitments | $ | 12 | | | $ | 4 | | | $ | 2 | | | $ | 2 | | | $ | 1 | | | $ | 1 | | | $ | 2 | |
| | | | | | | | | | | | | |
__________
(a)Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.
84
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Letters of credit (non-debt)(a) | $ | 1,276 |
| | $ | 1,193 |
| | $ | 14 |
| | $ | 22 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
Surety bonds(b) | 1,206 |
| | 1,079 |
| | 20 |
| | 40 |
| | 11 |
| | 21 |
| | 13 |
| | 4 |
| | 4 |
|
Financing trust guarantees | 378 |
| | — |
| | 200 |
| | 178 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Guaranteed lease residual values(c) | 19 |
| | — |
| | — |
| | — |
| | — |
| | 19 |
| | 6 |
| | 7 |
| | 5 |
|
Total commercial commitments | $ | 2,879 |
| | $ | 2,272 |
| | $ | 234 |
| | $ | 240 |
| | $ | 13 |
|
| $ | 41 |
| | $ | 20 |
| | $ | 11 |
| | $ | 9 |
|
_________
| |
(a) | Letters of credit (non-debt) - Exelon and certain subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. |
| |
(b) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(c) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $49 million, $14 million of which is a guarantee by Pepco, $19 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. |
Nuclear Insurance (Exelon and Generation)
Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of September 30, 2017, the current liability limit per incident is $13.4 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.0 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.8 billion, including CENG's related liability, however any amounts payable under this secondary layer would be capped at $420 million per year.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
In addition,(b)Represents the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4 billion limit for a single incident.
As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC of the Exelon 2016 Form 10-K for additional information on Generation’s operations relating to CENG.
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station sitemaximum potential obligation in the event that the fair value of an accident.certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The property insurance maintained for each facility is currently provided through insurance policies purchasedlease term associated with these assets ranges from NEIL, an industry mutual insurance company1 to 9 years. The maximum potential obligation at the end of the minimum lease term would be $65 million guaranteed by Exelon and PHI, of which Generation$21 million, $27 million, and $17 million is a member.
Premiums paid to NEILguaranteed by its members are also subject to a potential assessment for adverse loss experience inPepco, DPL, and ACE, respectively. Historically, payments under the formguarantees have not been made and PHI believes the likelihood of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predictpayments being required under the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generationguarantees is approximately $360 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.remote.
Environmental IssuesRemediation Matters
General (All Registrants)
General.. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federalfederal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
MGP Sites (All Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of thesesome sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has identified 4220 sites 19 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 23 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2022.2031.
•PECO has identified 266 sites 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 9 sitesthat are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.2024.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
•BGE has identified 13 former gas manufacturing or purification4 sites that it currently owns or owned at one time through a predecessor’s acquisition. Two of the gas manufacturing sites require some level of remediation andand/or ongoing monitoring underactivity. BGE expects the directionmajority of the MDE. The required costsremediation at these two sites are not considered material.In May 2017, BGE completed the additional work requested by MDE. All the sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required. For more information, see the discussion of the Riverside site below.
to continue through at least 2025.•DPL has identified 3 sites, 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining1 site that is currently under study and the required cost at the site is not consideredexpected to be material.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. ComEd and PECO have recorded regulatory assets for the recovery of these costs. See Note 5 — Regulatory Matters for additional information regarding the associated regulatory assets. BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. DPL has historically received recovery of actual clean-up costs in distribution rates.
As of September 30, 2017 and December 31, 2016, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
|
| | | | | | | |
September 30, 2017 | Total Environmental Investigation and Remediation Reserve | | Portion of Total Related to MGP Investigation and Remediation |
Exelon | $ | 429 |
|
| $ | 327 |
|
Generation | 76 |
| | — |
|
ComEd | 294 |
| | 293 |
|
PECO | 33 |
| | 32 |
|
BGE | 3 |
| | 2 |
|
PHI (Successor) | 23 |
|
| — |
|
Pepco | 21 |
| | — |
|
DPL | 1 |
| | — |
|
ACE | 1 |
| | — |
|
|
| | | | | | | |
December 31, 2016 | Total Environmental Investigation and Remediation Reserve | | Portion of Total Related to MGP Investigation and Remediation |
Exelon | $ | 429 |
|
| $ | 325 |
|
Generation | 72 |
| | — |
|
ComEd | 292 |
| | 291 |
|
PECO | 33 |
| | 31 |
|
BGE | 2 |
| | 2 |
|
PHI (Successor) | 30 |
|
| 1 |
|
Pepco | 27 |
| | — |
|
DPL | 2 |
| | 1 |
|
ACE | 1 |
| | — |
|
The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
During the third quarterComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are currently recovering environmental remediation costs of 2017, ComEd, PECO,former MGP facility sites through customer rates. While BGE and PHI completed an annual studyDPL do not have riders for MGP clean-up costs, they have historically received recovery of their future estimated MGP remediation requirements. The study resultedactual clean-up costs in a $13 million and $2 million increase to environmental liabilities and related regulatory assets for ComEd and PECO, respectively, and no change at BGE and PHI.distribution rates.
The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.
Water Quality
Benning Road Site NPDES Permit Limit Exceedances. Pepco holds an NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road service facility. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). The BMPs were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for all metals.
The 2009 permit remains in effect pending EPA’s action on the Pepco renewal application, including resolution of the stormwater compliance issues. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court, and in March 2016 the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. Since 2009 Pepco has installed runoff mitigation measures and implemented new operating procedures to comply with regulations. In January 2017, the parties agreed to a settlement in the form of a Consent Decree whereby Pepco will pay a civil penalty in the amount of $1.6 million, continue the BMPs to manage stormwater, construct a new stormwater treatment system, and make certain other capital improvements to the stormwater management system. On May 19, 2017, the Consent Decree was entered with the Court and became final. The Civil Penalty assessed under the Consent Decree of $1.6 million was paid on June 5, 2017 and other requirements of the Decree are now being implemented.
Solid and Hazardous Waste
Cotter Corporation.The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. This further analysis has focused on a partial excavation remedial option. The PRPs have provided a draft Remedial Investigation and Feasibility Study (RI/FS) report to the EPA for its review and comment. The final RI/FS will form the basis of EPA’s selection of a remedy from among the alternatives of a landfill cover, and partial or complete excavation. The EPA has advised the PRPs that the EPA announcement of the proposed remedy will take place in the first quarter of 2018. Thereafter, the EPA will select a final remedy and seek to enter into a Consent Decree with the PRPs to effectuate the remedy. Recent investigation has identified a number of other parties who may be PRPs and could be liable to contribute to the final remedy. Further investigation is on going.
The estimated cost of the landfill cover remedy (taking into account the current EPA technical requirements incorporated in the third quarter 2017) is approximately $110 million, including escalation, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of a landfill cover, which is included in the table above. Generation believes that a partial excavation remedy is reasonably possible, and the partial excavation costs, inclusive of a landfill cover, could range from approximately $225 million to $650 million; such costs would likely be shared by the final group of identified PRPs. Generation believes the likelihood that the EPA would require a complete excavation remedy is remote. The cost of a partial or complete excavation could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminentNote 12 — Commitments and dangerous conditions at the landfill. The first involved installation by the PRPs of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action. The second action involved EPA's public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, EPA has not provided sufficient details related to the basis for and the requirements and design of a barrier wall to enable Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to which Generation may have liability as a potentially responsible party, or develop a reasonable estimate of the potential incremental costs. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Generation's and Exelon's future results of operations and cash flows. Finally, one of the other PRPs, the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation and Exelon do not possess sufficient information to assess this claim and are therefore unable to determine the impact on their future results of operations and cash flows.
On February 2, 2016, the U.S. Senate passed a bill to transfer remediation authority over the West Lake Landfill from the EPA to the U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). The legislation was not passed in the U.S. House of Representatives, and would therefore require reintroduction in the Senate for consideration in the current session of Congress. Should such proposed legislation ultimately become law, it would be subject to annual funding appropriations in the U.S. Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but would likely delay the determination of a final remedy and its implementation.
On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August 2018 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability, which is included in the table above.
Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. The complaints do not contain specific damage claims. In the event of a finding of liability against Cotter, it is reasonably possible that Exelon would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of lawsuits, and is expected to dismiss additional lawsuits based on a recent ruling. Pre-trial motions and discovery are proceeding in the remaining cases and a pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd cannot estimate a range of loss, if any.
68th Street Dump. In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In connection with BGE's 2000 corporate restructuring the responsibility for this liability was transferred to Constellation and as a result of the 2012 Exelon and CEG merger is now Generation's responsibility. In March 2004, the PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and the PRPs
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)Contingencies
As of March 31, 2023 and December 31, 2022, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:
with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. On September 30, 2013, EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by EPA is consistent with the PRPs estimated range of costs noted above. In July, 2017 the PRPs and EPA finalized the terms of a Consent Decree which has been executed by the Parties and lodged with the U.S. District Court. After publication in the Federal Register there will be a 30-day public comment period after which it is anticipated it will be approved by the Court without any significant change in the costs for cleanup, Generation has elected to be a non-performing cash-out party and following payment of the allocated cost for its share of the clean-up. Generation will have no remaining liability at the site, except for unknown conditions that could manifest themselves after the settlement. The cash-out payment is included in the table above and is immaterial to the Generation and Exelon financial statements. | | | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2023 | | December 31, 2022 |
| Total environmental investigation and remediation liabilities | | Portion of total related to MGP investigation and remediation | | Total environmental investigation and remediation liabilities | | Portion of total related to MGP investigation and remediation |
Exelon | $ | 421 | | | $ | 343 | | | $ | 409 | | | $ | 355 | |
ComEd | 313 | | | 312 | | | 325 | | | 324 | |
PECO | 25 | | | 23 | | | 25 | | | 23 | |
BGE | 9 | | | 8 | | | 9 | | | 8 | |
PHI | 70 | | | — | | | 46 | | | — | |
Pepco | 68 | | | — | | | 44 | | | — | |
DPL | 1 | | | — | | | 1 | | | — | |
ACE | 1 | | | — | | | 1 | | | — | |
Rossville Ash Site. The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG), a wholly owned subsidiary of Generation. In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $1 million which has been fully reserved and included in the table above as of September 30, 2017.
Sauer Dump. On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRPs signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRPs to conduct a remedial investigation and feasibility study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. Although the ultimate outcome of this proceeding is uncertain based on the information complied to date, BGE has developed an estimate of the range of the probable liability; such costs would be shared by the 4 identified PRPs. BGE has accrued an appropriate reserve for its share of the estimated liabilities that is included it in the table above. It is possible, however, that final resolution of this matter could have a material, unfavorable impact on BGE’s future results of operations and cash flows.
Riverside. In 2013, the MDE, at the request of EPA, conducted a site inspection and limited environmental sampling of certain portions of the 170 acre Riverside property owned by BGE. The site consists of several different parcels with different current and historical uses. The sampling included soil and groundwater samples for a number of potential environmental contaminants. The sampling confirmed the existence of contaminants consistent with the known historical uses of the various portions of the site. In March 2014, the MDE requested that BGE conduct an investigation which included a site-wide investigation of soils, sediment, groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report was provided to MDE in June 2015. In November 2015, MDE provided BGE with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, including off-site sediment and soil sampling. MDE did not request any interim remediation at this time and in May 2017 BGE completed the additional work requested by MDE. All the offsite sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required. MDE has provided BGE with the required clean-up levels for the on-site contamination and BGE is moving forward with the necessary remediation as directed by MDE. BGE has established what it believes is an appropriate reserve based upon the information available to date, and this amount is included in the table above. As the remediation proceeds, it is possible that additional reserves could be established, in amounts that could be material to BGE.
BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. Additionally, legislation was passed during the 2017 Maryland General Assembly session that should further support BGE’s recovery of its clean-up costs.
Benning Road Site. Site (Exelon, PHI, and Pepco).In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of aan electric generating facility owned by Pepco subsidiary, Pepco Energy Services electric generating facility. That(PES), which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility was deactivated
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
in June 2012 and plant structure demolition was completed in July 2015.2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a consent decreeConsent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco and Pepco Energy ServicesEntities to conduct a RemediationRemedial Investigation (RI)/and Feasibility Study (FS)(RI/FS) for the Benning Road site and an approximately 10 to 15 acre15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS will formis to define the basis for the remedial actions fornature and extent of contamination from the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. evaluate remedial alternatives.
Pursuant to Exelon's March 23, 2016 acquisition of PHI,an internal agreement between the Pepco Energy Services was transferred to Generation. On July 1, 2017,Entities, since 2013, Pepco Energy Services was merged into Constellation New Energy, a subsidiary of Generation.
The initial RI fieldhas performed the work began in January 2013required by the Consent Decree and was completed in December 2014. In April 2015, Pepco and Pepco Energy Services submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis was required to complete the RI process (much of which was beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services revised the draft RI Report to address DOEE’s comments and DOEE released the draft RI Report for public review in February 2016. Once the additional RI work has been completed,reimbursed for that work by an agreed upon allocation of costs between the Pepco and Generation will issueEntities. In September 2019, the Pepco Entities issued a draft “final” RI report for review and comment bywhich DOEE and the public.approved on February 3, 2020. The Pepco and Generation will then proceed to develop anEntities are completing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established aIn October 2022, DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the RIproject. After completion and FS, and approval by the DOEE, by June 2018.
Upon DOEE’s approval of the final RI andlandside FS, Reports, Pepco and Generation will have satisfied their obligations under the consent decree. At that point,now scheduled for September 2023, DOEE will prepare a Proposed Plan regarding further response actions. After consideringfor public comment on the Proposed Plan, DOEE willand then issue a Record of Decision (ROD) identifying any further response actions determined to be necessary.necessary to address any landside issues. The DOEE will issue a separate ROD for the waterside FS when that work is completed which is now anticipated to be by March 31, 2024.
As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, Pepco and GenerationPepco have determined that a loss associated with this matter for PHI, Pepco and Generation is probable and have accrued an estimated liability, for this issue has been accrued, which is included in the table above. As the remedial investigation proceeds and potential remedies are identified, it is possible that additional accruals could be established in amounts that could be material to PHI and Pepco. The ultimate resolution of this matter is currently not expected to have any significant financial impact on Generation.
Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by the Pepco and Generation,Entities, DOEE and certain federal agenciesNPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C.Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by the Pepco and Pepco Energy ServicesEntities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road RI/FS. Pepco responded that it will participate in the Consultative Working Group but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. DOEE has advised the Consultative Working Group that the federal and DOEE authorities are conducting phase 2 of a remedial investigation and that a feasibility study of potential remedies is expected to be completed in December 2017. A proposed remedy for the clean-up of sediments in this section of the river is expected to be released for public comment in February 2018 and the DOEE has targeted June 2018 as the date for remedy selection. The Consultative Working Group and the other possible PRPs have provided input into the proposed clean-up process and schedule. At this time, it is not possible to predict the extent of Pepco’s participation in the river-wide RI/FS process, and Pepco cannot estimate the reasonably possible range of loss for response costs beyond those associated with the Benning RI/FS component of the river-wide initiative. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and Pepco’s future results of operations and cash flows.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
Conectiv Energy Wholesale Power Generation Sites. In July 2010, PHI soldOn September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the wholesale power generation business of Conectiv Energy Holdings, Inc.river to be addressed first while continuing to conduct studies and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA),monitor the transfer of ownershipriver to Calpine triggered an obligation onevaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine assumed responsibility for performing the ISRA-required remediation andplan for the payment of all related ISRA compliance costs upBenning Road site to $10 million. Predecessor PHI was obligatedproceed to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the 9 generating facility sites are in the range of approximately $7 million to $18 million, and predecessor PHI established an appropriate accrual for its share of the estimated clean-up costs. Pursuant to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred to Generation and the accrual for Predecessor PHI's share of the estimated clean- up costs was also transferred to Generation and is included in the table above as a liability of Generation. The responsibility to indemnify Calpine is shared by PHI and Generation. The ultimate resolution of this matter is currently not expected to have a material financial impact on PHI and Generation.conclusion.
Rock Creek Mineral Oil Release. In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirements of a February 29, 2016 compliance order which requires Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.
PHI and Pepco have reached a settlement with a third party who contributed to the loss. Exelon, PHI and Pepco do not believe that the balance of the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.
Brandywine Fly Ash Disposal Site. In February 2013,On July 15, 2022, Pepco received a letter from the MDE requestingDistrict of Columbia's Office of the Attorney General (D.C. OAG) on behalf of DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 to enter into settlement discussions. Since that time Exelon and the other PRPs at the site have exchanged letters with the D.C. OAG exploring potential settlement options. Those discussions are ongoing. Exelon, PHI, and Pepco investigatehave determined that it is probable that costs for remediation will be incurred and have accrued a liability for management's best estimate of its share of the extentcosts. Pepco concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of waste onloss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco right-of-waybecame aware that traverses the Brandywine fly ash disposal siteTrustees are in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for developmentbeginning stages of a closure planNRD assessment, a process that often takes many years beyond the remedial decision to MDE on September 30, 2013complete. Pepco has entered into negotiations with the Trustees to evaluate possible incorporation of NRD assessment and restoration as part of its remedial activities associated with the Benning site to accelerate the NRD benefits for that portion of the Anacostia River Sediment Project (ARSP) assessment. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process.
As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the ARSP was also assumed by this entity.
Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter dated October 18, 2013, MDE approvedfrom the schedule.
D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. The D.C. OAG invited Pepco to resolve the threatened enforcement action through a court-approved consent decree, and Pepco is engaged in discussions with the D.C. OAG regarding a potential resolution. Exelon, PHI, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability. Pepco concluded that the costs for implementation of a closure plan and cap on the site are inincremental exposure is reasonably possible, but the range of approximately $3 million to $6 million, for which an appropriate reserve has been established and isloss cannot be reasonably estimated beyond the amounts included in the table above. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.
Litigation and Regulatory Matters
Asbestos Personal Injury ClaimsDPA and Related Matters (Exelon Generation,and ComEd). Exelon and ComEd PECOreceived a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and BGE)
ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon Generation and PECO. Generation maintainsComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a reserve for claimsDPA with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEdthose jobs and PECO. The reserve is recorded on an undiscounted basis and excludessubcontracts for the estimated legal costs associated with handling these matters, which could be material.
At September 30, 2017 and December 31, 2016, Generation had reserved approximately $80 million and $83 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2017, approximately $22 million of this amount related to 227 open claims presented to Generation, while the remaining $58 millionbenefit of the reserve is for estimated future asbestos-related bodily injury claims anticipatedformer Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to arise through 2050, based on actuarial
influence the Speaker’s action regarding legislation affecting ComEd’s
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary.
On November 22, 2013, the Supreme Court of Pennsylvania heldinterests. The DPA provides that the Pennsylvania Workers Compensation Act does not apply to an employee’s disabilityUSAO will defer any prosecution of such charge and any other criminal or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Since the Pennsylvania Supreme Court's ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been reserved for on a claim by claim basis. Those additional claims are taken into account in projecting estimates of future asbestos-related bodily injury claims.
On November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois' Workers' Compensation Act and the Workers' Occupational Diseases Act barred an employee from bringing a direct civil actioncase against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court's ruling reversed previous rulings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker's Compensation law should not apply in cases where the diagnosis of an asbestos related disease occurred after the 25-year maximum time period for filing a Worker's Compensation claim. Since the Illinois Supreme Court’s ruling in November 2015, Exelon, Generation, and ComEd have not experienced a significant increase in asbestos-related personal injury claims brought by former ComEd employees.
There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material adverse effect on Exelon's, Generation's, ComEd's, PECO and BGE's future results of operations and cash flows.
BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.
To date, most asbestos claims which have been resolved relating to BGE and certain Constellation subsidiaries have been dismissed or resolved without any payment and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results. Presently, there are an immaterial number of asbestos cases pending against BGE and certain Constellation subsidiaries.
Continuous Power Interruption (Exelon and ComEd)
Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recoverymatters identified therein for a three-year period subject to certain obligations of consequential damages is barred.ComEd, including payment to the U.S. Treasury of $200 million, which was paid in November 2020. Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. The affected utility may seek fromSEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the ICC a waiver of these liabilities whenSEC. Exelon and ComEd cannot predict the utility can show that the causeoutcome of the interruption was unpreventable damage dueSEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to weather events or conditions, customer tampering, or certain other causes enumeratedthe SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.
Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits were filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the law. AsDPA and the SEC's investigation, including:
•Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of September 30, 2017 and December 31, 2016, ComEd did not have any material liabilities recorded for these storm events.
Baltimore City Franchise Taxes (Exelon and BGE)
The City of Baltimore claims that BGE has maintained electric facilitiescustomers in the City’s public right-of-ways for over one hundred years withoutthird quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, the proper franchise rights fromCitizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. On September 9, 2021, the City. BGEfederal court granted Exelon’s and ComEd’s motion to dismiss and dismissed the plaintiffs’ and CUB’s federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs and CUB on jurisdictional grounds. Plaintiffs appealed dismissal of the federal law claim to the Seventh Circuit Court of Appeals. Plaintiffs and CUB also refiled their state law claims in state court and moved to consolidate them with the already pending consumer state court class action, discussed below. On August 22, 2022, the Seventh Circuit affirmed the dismissal of the consolidated federal cases in their entirety. The time to further appeal has reviewedpassed and the City's claimSeventh Circuit’s decision is final.
•Three putative class action lawsuits against ComEd and believes that it lacks merit. BGE has not recordedExelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In November 2020, CUB filed a motion to intervene in the cases pursuant to an accrual for payment of franchise fees for past periodsIllinois statute allowing CUB to intervene as a rangeparty or otherwise participate on behalf of loss, ifutility consumers in any cannot be reasonably estimated at this time. Franchise fees assessedproceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB's request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs discussed above, to jointly engage in future periods may be materialmediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On December 23, 2021, the state court granted ComEd and Exelon's motion to BGE’s resultsdismiss with prejudice. On December 30, 2021, plaintiffs filed a motion to reconsider that dismissal and for permission to amend their complaint. The court denied the plaintiffs' motion on January 21, 2022. Plaintiffs have appealed the court's ruling dismissing their complaint to the First District Court of operationsAppeals. On February 15, 2022, Exelon and cash flows.ComEd moved to dismiss the federal plaintiffs' refiled state law claims, seeking dismissal on the same legal grounds asserted in their motion to dismiss the original state court plaintiffs' complaint. The court granted dismissal of the refiled state claims on February 16, 2022. The original federal plaintiffs appealed that dismissal on February 18, 2022. The two state appeals were consolidated on March 21, 2022. The appellate briefing is complete and the parties are awaiting oral argument and/or a decision.
•On November 3, 2022, a plaintiff filed a putative class action complaint in Lake County, Illinois Circuit Court against ComEd and Exelon for unjust enrichment and deceptive business practices in connection with the conduct giving rise to the DPA. Plaintiff seeks an accounting and disgorgement of any benefits ComEd allegedly obtained from said conduct. Plaintiff served initial discovery requests on ComEd in December 2022, to which ComEd has responded. ComEd and Exelon filed a motion to dismiss the Complaint on February 3, 2023. The parties fully briefed the motion, and on April 21, 2023, the court heard oral argument on the motion. The court expects to issue its ruling on the motion to dismiss on or before June 9, 2023.
•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
Conduit Lease with Cityrelated to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of Baltimore (Exelonthe original defendants and BGE)
add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021. That motion was denied on January 28, 2022. In May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint and the parties engaged thereafter in discovery. On September 23, 2015,9, 2021, the Baltimore CityU.S. government moved to intervene in the lawsuit and stay discovery until the parties entered into an amendment to their protective order that would prohibit the parties from requesting discovery into certain matters, including communications with the U.S. government. The court ordered said amendment to the protective order on November 15, 2021 and discovery resumed. The court further amended the protective order on October 17, 2022 and extended it until May 15, 2023. The next court status is set for June 27, 2023. Based on recent developments, management has determined that a probable loss exists for this matter in the amount of $173 million. Management anticipates that such loss would be fully covered by insurance. The probable loss and the expected insurance recovery are reflected in Exelon's Consolidated Balance Sheets within Accrued expenses and Other accounts receivable, respectively.
•Several shareholders have sent letters to the Exelon Board of Estimates approved an increase in annual rental fees for accessDirectors since 2020 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the Baltimore City underground conduit system effective November 1, 2015, from $12 millionconduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to $42 million, subjectinvestigate and address these shareholders’ allegations and make recommendations to an annual increase thereafterthe Exelon Board of Directors based on the Consumer Price Index. BGE subsequently enteredoutcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay has been extended several times. On March 27, 2023, the court issued an order further extending the stay until June 9, 2023, with a status report due by May 31, 2023. The parties participated in a mediation in February 2023 and efforts to resolve the matter remain ongoing. On April 26 and May 1, 2023, two additional demand letter shareholders each filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and certain third parties, and against Exelon as nominal defendant, asserting claims similar to those made in their respective demand letters.
•Several shareholders have sent requests seeking review of certain Exelon books and records since August 2021. Exelon has responded to each request.
Except as noted above, no loss contingencies have been reflected in Exelon's and ComEd's consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.
In August 2022, the ICC concluded its investigation initiated on August 12, 2021 into litigationrate impacts of conduct admitted in the DPA, including the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. On August 17, 2022, the ICC issued its final order accepting ComEd's voluntary customer refund offer of approximately $38 million (of which about $31 million is ICC jurisdictional; the remaining balance is FERC jurisdictional) that resolves the question of whether customer funds were used for DPA related activities. The customer refund includes the cost of every individual or entity that was either (i) identified in the DPA or (ii) identified by ComEd as an associate of the former Speaker of the Illinois House of Representatives in the ICC proceeding. The ICC rejected an argument by the Illinois Attorney General, City of Chicago, and CUB that a costly permanent adjustment also needed to be made to ComEd's ratemaking capital structure on account of Exelon having funded ComEd's payment of the DPA fine with an equity infusion. On October 6, the ICC denied the application for rehearing filed by the Illinois Attorney General, City regardingof Chicago, and CUB that specifically focused on their capital structure argument. The window to file an appeal on the ICC final order has expired and the ICC’s DPA investigation is now closed. An accrual for the amount of the customer refund has been recorded in Regulatory liabilities and basisRegulatory assets in Exelon’s and ComEd’s Consolidated Balance Sheets as of March 31, 2023. The ICC jurisdictional refund is being made to customers during the April 2023 billing cycle, as required by the ICC. The FERC jurisdictional refund will be made as part of the next transmission formula rate
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
update proceeding in 2023. The customer refund will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon.
Savings Plan Claim (Exelon). On December 6, 2021, seven current and former employees filed a putative ERISA class action suit in U.S. District Court for establishing the conduit fee.Northern District of Illinois against Exelon, its Board of Directors, the former Board Investment Oversight Committee, the Corporate Investment Committee, individual defendants, and other unnamed fiduciaries of the Exelon Corporation Employee Savings Plan (Plan). The complaint alleges that the defendants violated their fiduciary duties under the Plan by including certain investment options that allegedly were more expensive than and underperformed similar passively-managed or other funds available in the marketplace and permitting a third-party administrative service provider/recordkeeper and an investment adviser to charge excessive fees for the services provided. The plaintiffs seek declaratory, equitable and monetary relief on behalf of the Plan and participants. On February 16, 2022, the court granted the parties' stipulated dismissal of the individual named defendants without prejudice. The remaining defendants filed a motion to dismiss the complaint on February 25, 2022. On March 4, 2022, the Chamber of Commerce filed a brief of amicus curiae in support of the defendants' motion to dismiss. On September 22, 2022, the court granted Exelon’s motion to dismiss without prejudice. The court granted plaintiffs leave until October 31, 2022 to file an amended complaint, which was later extended to November 30, 2016,2022. Plaintiffs filed their amended complaint on November 30, 2022. Defendants filed their motion to dismiss the Baltimore City Board of Estimates approved a settlement agreement entered into between BGEamended complaint on January 20, 2023. Briefing on the motion to dismiss is now complete and the Cityparties await a ruling. No loss contingencies have been reflected in Exelon’s consolidated financial statements with respect to resolve the disputes and pending litigation related to BGE's use of and payment for the underground conduit system. As a result of the settlement, the parties have entered into a six-year lease that reduces the annual expense to $25 million in the first three years and caps the annual expense in the last three years to not more than $29 million. BGE recorded a credit to Operating and maintenance expense in the fourth quarter of 2016 of approximately $28 million for the reversal of the previously higher fees accrued in the current yearthis matter, as well as the settlement of prior year disputed fee true-up amounts.
Deere Wind Energy Assets (Exelon and Generation)
In 2013, Deere & Company (“Deere”) filed a lawsuit against Generation in the Delaware Superior Court relating to Generation’s acquisition of the Deere wind energy assets. Under the purchase agreement, Deere was entitled to receive earn-out payments if certain specific wind projects already under development in Michigan met certain development and construction milestones following the sale. In the complaint, Deere seeks to recover a $14 million earn-out payment associated with one such project, which was never completed. Generation has filed counterclaims against Deere for breach of contract, with a right of recoupment and set off. On June 2, 2016, the Delaware Superior Court entered summary judgment in favor of Deere. On January 17, 2017, Generation filed an appeal of the Superior Court’s summary judgment decision with the Supreme Court of Delaware. Generation has accrued an amount to cover its potential liability.
City of Everett Tax Increment Financing Agreement (Exelon)
The City of Everett has filed a petition with the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic 8 & 9 on the grounds that the total investment in Mystic 8 & 9 materially deviates from the investment set forth in the TIF Agreement. The EACC has appointed a three-member panel to conduct an administrative hearing on the City’s petition. Generation has reviewed the City’s claim and believes that it lacks merit. Generation has not recorded an accrual for payment resulting from such a revocation because the range of loss, if any, cannot becontingencies are neither probable nor reasonably estimatedestimable at this time. Property taxes assessed in future periods could be material to Generation’s results of operations and cash flows.
General (All Registrants)
. The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or a reasonable possibility,reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
Income Taxes (Exelon, Generation, ComEd, PECO
13. Shareholders' Equity (Exelon)
At-the-Market (ATM) Program
On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and BGE)
See Note 12 — Income Taxes for information regarding the Registrants’ income tax refund claimsforward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common Stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of Common Stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement. As of March 31, 2023, Exelon has not issued any shares of Common Stock under the ATM program and has not entered into any forward sale agreements.
14. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, positions, including the 1999 sale of fossil generating assets.by component:
| | | | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2023 | Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign Currency Items | | | | Total |
Balance as of December 31, 2022 | $ | 2 | | | $ | (640) | | | $ | — | | | | | $ | (638) | |
OCI before reclassifications | 6 | | | (10) | | | — | | | | | (4) | |
Amounts reclassified from AOCI | — | | | 3 | | | — | | | | | 3 | |
Net current-period OCI | 6 | | | (7) | | | — | | | | | (1) | |
Balance as of March 31, 2023 | $ | 8 | | | $ | (647) | | | $ | — | | | | | $ | (639) | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Changes in Accumulated Other Comprehensive Income
19. | | | | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2022 | Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items(a) | | Foreign Currency Items | | | | Total |
Balance as of December 31, 2021 | $ | (6) | | | $ | (2,721) | | | $ | (23) | | | | | $ | (2,750) | |
Separation of Constellation | 6 | | | 1,994 | | | 23 | | | | | 2,023 | |
| | | | | | | | | |
Amounts reclassified from AOCI | — | | | 14 | | | — | | | | | 14 | |
Net current-period OCI | — | | | 14 | | | — | | | | | 14 | |
Balance as of March 31, 2022 | $ | — | | | $ | (713) | | | $ | — | | | | | $ | (713) | |
__________(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. Additionally, as of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 14 — Retirement Benefits of the 2022 Form 10-K and Note 8 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
The following table presents Income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):
| | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, | | |
| | | | | 2023 | | 2022 | | | | |
Pension and non-pension postretirement benefit plans: | | | | | | | | | | | |
| | | | | | | | | | | |
Actuarial loss reclassified to periodic benefit cost | | | | | $ | (1) | | | $ | (5) | | | | | |
Pension and non-pension postretirement benefit plans valuation adjustment | | | | | 3 | | | — | | | | | |
Unrealized gain on cash flow hedges | | | | | (1) | | | — | | | | | |
| | | | | | | | | | | |
15. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants’Registrants' Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2017 and 2016.Income:
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| Taxes other than income taxes |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Three Months Ended March 31, 2023 | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 220 | | | $ | 74 | | | $ | 40 | | | $ | 29 | | | $ | 77 | | | $ | 68 | | | $ | 8 | | | $ | 1 | |
Property | 99 | | | 10 | | | 4 | | | 50 | | | 35 | | | 24 | | | 11 | | | — | |
Payroll | 32 | | | 7 | | | 5 | | | 5 | | | 7 | | | 2 | | | 1 | | | 1 | |
| | | | | | | | | | | | | | | |
Three Months Ended March 31, 2022 | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 221 | | | $ | 78 | | | $ | 38 | | | $ | 27 | | | $ | 78 | | | $ | 70 | | | $ | 7 | | | $ | 1 | |
Property | 94 | | | 10 | | | 4 | | | 46 | | | 34 | | | 23 | | | 10 | | | 1 | |
Payroll | 37 | | | 7 | | | 4 | | | 4 | | | 7 | | | 2 | | | 1 | | | 1 | |
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_________ |
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| Three Months Ended September 30, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Other, Net | | | | | | | | | | | | | | | | | |
Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on decommissioning trust funds(a) | | | | | | | | | | | | | | | | | |
Regulatory agreement units | $ | 159 |
| | $ | 159 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Non-regulatory agreement units | 59 |
| | 59 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net unrealized gains on decommissioning trust funds | | | | | | | | | | | | | | | | | |
Regulatory agreement units | 44 |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-regulatory agreement units | 111 |
| | 111 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
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|
Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | |
Zion Station decommissioning | (4 | ) | | (4 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to decommissioning trust fund-related activities(b) | (161 | ) | | (161 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total decommissioning-related activities | 208 |
| | 208 |
| | — |
| | — |
| | — |
|
| — |
| | — |
| | — |
| | — |
|
Investment income | 2 |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
|
Interest income related to uncertain income tax positions | 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
AFUDC — Equity | 17 |
| | — |
| | 2 |
| | 2 |
| | 4 |
| | 9 |
| | 6 |
| | 2 |
| | 1 |
|
Other | 6 |
| | — |
| | 3 |
| | — |
| | — |
| | 3 |
| | — |
| | 2 |
| | — |
|
Other, net | $ | 237 |
|
| $ | 209 |
|
| $ | 5 |
|
| $ | 2 |
|
| $ | 4 |
|
| $ | 13 |
|
| $ | 7 |
|
| $ | 4 |
|
| $ | 1 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Other, Net | | | | | | | | | | | | | | | | | |
Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on decommissioning trust funds(a) | | | | | | | | | | | | | | | | | |
Regulatory agreement units | $ | 439 |
| | $ | 439 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Non-regulatory agreement units | 165 |
| | 165 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net unrealized gains on decommissioning trust funds | | | | | | | | | | | | | | | | | |
Regulatory agreement units | 253 |
| | 253 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-regulatory agreement units | 347 |
| | 347 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | |
Zion Station decommissioning | (5 | ) | | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to decommissioning trust fund-related activities(b) | (558 | ) | | (558 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total decommissioning-related activities | 641 |
| | 641 |
| | — |
| | — |
| | — |
| | — |
|
| — |
| | — |
| | — |
|
Investment income | 6 |
| | 4 |
| | — |
| | — |
| | — |
| | 2 |
| | 1 |
| | — |
| | — |
|
Interest income related to uncertain income tax positions | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Benefit related to uncertain income tax positions(c) | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
AFUDC — Equity | 51 |
| | — |
| | 6 |
| | 6 |
| | 12 |
| | 27 |
| | 17 |
| | 5 |
| | 5 |
|
Other | 22 |
| | 3 |
| | 8 |
| | — |
| | — |
| | 11 |
| | 4 |
| | 5 |
| | 1 |
|
Other, net | $ | 725 |
|
| $ | 648 |
|
| $ | 14 |
|
| $ | 6 |
|
| $ | 12 |
| | $ | 40 |
|
| $ | 22 |
|
| $ | 10 |
|
| $ | 6 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2016 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Other, Net | | | | | | | | | | | | | | | | | |
Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on decommissioning trust funds(a) | | | | | | | | | | | | | | | | | |
Regulatory agreement units | $ | 57 |
| | $ | 57 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Non-regulatory agreement units | 35 |
| | 35 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net unrealized gains on decommissioning trust funds | | | | | | | | | | | | | | | | | |
Regulatory agreement units | 155 |
| | 155 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-regulatory agreement units | 116 |
| | 116 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | |
Zion Station decommissioning | (5 | ) | | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to decommissioning trust fund-related activities(b) | (168 | ) | | (168 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total decommissioning-related activities | 190 |
| | 190 |
| | — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
| | — |
|
Investment income (expense) | 2 |
| | 1 |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Interest income related to uncertain income tax positions | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Penalty related to uncertain income tax positions(c) | (106 | ) | | — |
| | (86 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
AFUDC — Equity | 19 |
| | — |
| | 5 |
| | 2 |
| | 5 |
| | 7 |
| | 5 |
| | 1 |
| | 1 |
|
Other | 7 |
| | (6 | ) | | 1 |
| | 1 |
| | — |
| | 12 |
| | 7 |
| | 2 |
| | 1 |
|
Other, net | $ | 120 |
|
| $ | 185 |
|
| $ | (80 | ) |
| $ | 2 |
|
| $ | 5 |
| | $ | 19 |
|
| $ | 12 |
|
| $ | 3 |
|
| $ | 2 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| Nine Months Ended September 30, 2016 | | March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Other, Net | | | | | | | | | | | | | | | | | | | | |
Decommissioning-related activities: | | | | | | | | | | | | | | | | | | | | |
Net realized income on decommissioning trust funds(a) | | | | | | | | | | | | | | | | | | | | |
Regulatory agreement units | $ | 181 |
| | $ | 181 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
Non-regulatory agreement units | 95 |
| | 95 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Net unrealized gains on decommissioning trust funds | | | | | | | | | | | | | | | | | | | | |
Regulatory agreement units | 286 |
| | 286 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Non-regulatory agreement units | 216 |
| | 216 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | | | | |
Zion Station decommissioning | (2 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Regulatory offset to decommissioning trust fund-related activities(b) | (380 | ) | | (380 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Total decommissioning-related activities | 396 |
| | 396 |
| | — |
| | — |
| | — |
|
| — |
| | — |
| | — |
| | — |
| | | — |
|
Investment income (expense) | 14 |
| | 6 |
| | — |
| | (1 | ) | | 2 |
| | — |
| | — |
| | — |
| | 1 |
| | | — |
|
Long-term lease income | 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Interest income related to uncertain income tax positions | 13 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | | — |
|
Penalty related to uncertain income tax positions(c) | (106 | ) | | — |
| | (86 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
AFUDC — Equity | 43 |
| | — |
| | 8 |
| | 6 |
| | 14 |
| | 14 |
| | 3 |
| | 5 |
| | 15 |
| | | 7 |
|
Loss on debt extinguishment | (3 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Other | 16 |
| | (5 | ) | | 6 |
| | 1 |
| | — |
| | 13 |
| | 6 |
| | 2 |
| | 15 |
| | | (11 | ) |
Other, net | $ | 377 |
|
| $ | 395 |
|
| $ | (72 | ) |
| $ | 6 |
|
| $ | 16 |
|
| $ | 28 |
| | $ | 9 |
| | $ | 8 |
| | $ | 31 |
| | | $ | (4 | ) |
_________
| |
(a) | Includes investment income and realized gains and losses on sales of investments of the trust funds. |
| |
(b) | Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 16 — Asset Retirement Obligations of the Exelon 2016 Form 10-K for additional information regarding the accounting for nuclear decommissioning. |
| |
(c) | See Note 12 - Income Taxes for discussion of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position.
|
(a)The followingRegistrants' utility taxes are included in revenues and expenses for the three and nine months ended September 30, 2017 and 2016. Generation’s utility tax expense represents gross receipts tax related to its retail operations, and the utility registrants' utility tax expense representsrepresent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
91
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Utility taxes | $ | 245 |
|
| $ | 35 |
|
| $ | 65 |
|
| $ | 35 |
|
| $ | 22 |
| | $ | 88 |
| | $ | 83 |
|
| $ | 5 |
|
| $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Utility taxes | $ | 682 |
|
| $ | 97 |
|
| $ | 181 |
|
| $ | 95 |
|
| $ | 69 |
| | $ | 240 |
| | $ | 226 |
|
| $ | 14 |
|
| $ | — |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2016 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Utility taxes | $ | 255 |
|
| $ | 35 |
|
| $ | 67 |
|
| $ | 40 |
|
| $ | 21 |
| | $ | 92 |
| | $ | 87 |
|
| $ | 5 |
|
| $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| Nine Months Ended September 30, 2016 | | March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Utility taxes | $ | 624 |
|
| $ | 90 |
|
| $ | 186 |
|
| $ | 106 |
|
| $ | 66 |
| | $ | 240 |
|
| $ | 14 |
|
| $ | — |
| | $ | 176 |
| | | $ | 78 |
|
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Depreciation, amortization and accretion | | | | | | | | | | | | | | | | | |
Property, plant and equipment(a) | $ | 2,416 |
| | $ | 1,010 |
| | $ | 579 |
| | $ | 194 |
| | $ | 233 |
| | $ | 342 |
| | $ | 153 |
| | $ | 92 |
| | $ | 66 |
|
Amortization of regulatory assets(a) | 355 |
| | — |
| | 52 |
| | 19 |
| | 115 |
| | 169 |
| | 89 |
| | 32 |
| | 47 |
|
Amortization of intangible assets, net(a) | 43 |
| | 36 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of energy contract assets and liabilities(b) | 19 |
| | 19 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Nuclear fuel(c) | 816 |
| | 816 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
ARO accretion(d) | 350 |
| | 350 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total depreciation, amortization and accretion | $ | 3,999 |
|
| $ | 2,231 |
|
| $ | 631 |
|
| $ | 213 |
|
| $ | 348 |
| | $ | 511 |
| | $ | 242 |
|
| $ | 124 |
|
| $ | 113 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| Nine Months Ended September 30, 2016 | | March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Depreciation, amortization and accretion | | | | | | | | | | | | | | | | | | | | |
Property, plant and equipment(a) | $ | 2,490 |
| | $ | 1,297 |
| | $ | 524 |
| | $ | 181 |
| | $ | 223 |
| | $ | 128 |
| | $ | 82 |
| | $ | 61 |
| | $ | 215 |
| | | $ | 94 |
|
Amortization of regulatory assets(a) | 293 |
| | — |
| | 49 |
| | 20 |
| | 84 |
| | 93 |
| | 38 |
| | 69 |
| | 140 |
| | | 58 |
|
Amortization of intangible assets, net(a) | 38 |
| | 32 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of energy contract assets and liabilities(b) | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Nuclear fuel(c) | 862 |
| | 862 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
ARO accretion(d) | 333 |
| | 332 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Total depreciation, amortization and accretion | $ | 4,009 |
|
| $ | 2,516 |
|
| $ | 574 |
|
| $ | 201 |
|
| $ | 307 |
| | $ | 221 |
|
| $ | 120 |
|
| $ | 130 |
| | $ | 355 |
| | | $ | 152 |
|
_________
| |
(a) | Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income. |
| |
(b) | Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
| |
(c) | Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
| |
(d) | Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Other non-cash operating activities: | | | | | | | | | | | | | | | | | |
Pension and non-pension postretirement benefit costs | $ | 482 |
| | $ | 170 |
| | $ | 131 |
| | $ | 21 |
| | $ | 47 |
| | $ | 72 |
| | $ | 19 |
| | $ | 10 |
| | $ | 10 |
|
Loss from equity method investments | 26 |
| | 26 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Provision for uncollectible accounts | 103 |
| | 31 |
| | 25 |
| | 17 |
| | 4 |
| | 26 |
| | 11 |
| | 1 |
| | 14 |
|
Stock-based compensation costs | 76 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other decommissioning-related activity(a) | (213 | ) | | (213 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy-related options(b) | 15 |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of regulatory asset related to debt costs | 7 |
| | — |
| | 3 |
| | 1 |
| | — |
| | 3 |
| | 1 |
| | 1 |
| | 1 |
|
Amortization of rate stabilization deferral | (7 | ) | | — |
| | — |
| | — |
| | 7 |
| | (14 | ) | | (12 | ) | | (2 | ) | | — |
|
Amortization of debt fair value adjustment | (13 | ) | | (9 | ) | | — |
| | — |
| | — |
| | (4 | ) | | — |
| | — |
| | — |
|
Discrete impacts from EIMA and FEJA(c) | (61 | ) | | — |
| | (61 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of debt costs | 57 |
| | 33 |
| | 3 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
|
Provision for excess and obsolete inventory
| 52 |
| | 50 |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | — |
|
Merger-related commitments(d) | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | (6 | ) | | (2 | ) | | — |
|
Severance costs | 33 |
| | 25 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
Other | 46 |
| | 4 |
| | 10 |
| | (2 | ) | | (7 | ) | | (14 | ) | | (6 | ) | | (3 | ) | | (4 | ) |
Total other non-cash operating activities | $ | 603 |
|
| $ | 132 |
|
| $ | 112 |
|
| $ | 38 |
|
| $ | 52 |
| | $ | 66 |
| | $ | 8 |
|
| $ | 6 |
|
| $ | 21 |
|
Non-cash investing and financing activities: | | | | | | | | | | | | | | |
Change in capital expenditures not paid | $ | (101 | ) | | $ | 20 |
| | $ | (79 | ) | | $ | (29 | ) | | $ | 16 |
| | $ | (6 | ) | | $ | 7 |
| | $ | 14 |
| | $ | (18 | ) |
Fair value of pension obligation transferred in connection with the FitzPatrick acquisition | — |
| | 33 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Change in PPE related to ARO update | (141 | ) | | (141 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Indemnification of like-kind exchange position(g) | — |
| | — |
| | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-cash financing of capital projects | 16 |
| | 16 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Dividends on stock compensation | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| — |
| | — |
|
Dissolution of financing trust due to long-term debt retirement | 8 |
| | — |
| | — |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
|
Fair value adjustment of long-term debt due to retirement | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| Nine Months Ended September 30, 2016 | | March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Other non-cash operating activities: | | | | | | | | | | | | | | | | | | | | |
Pension and non-pension postretirement benefit costs | $ | 458 |
| | $ | 163 |
| | $ | 124 |
| | $ | 25 |
| | $ | 50 |
| | $ | 24 |
| | $ | 13 |
| | $ | 11 |
| | $ | 58 |
| | | $ | 23 |
|
Loss from equity method investments | 15 |
| | 16 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Provision for uncollectible accounts | 107 |
| | 14 |
| | 31 |
| | 24 |
| | 12 |
| | 15 |
| | 12 |
| | 18 |
| | 27 |
| | | 16 |
|
Stock-based compensation costs | 88 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | 3 |
|
Other decommissioning-related activity(a) | (237 | ) | | (237 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Energy-related options(b) | (20 | ) | | (20 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of regulatory asset related to debt costs | 7 |
| | — |
| | 3 |
| | 1 |
| | — |
| | 2 |
| | — |
| | 1 |
| | 2 |
| | | 1 |
|
Amortization of rate stabilization deferral | 62 |
| | — |
| | — |
| | — |
| | 62 |
| | 3 |
| | 3 |
| | — |
| | — |
| | | 5 |
|
Amortization of debt fair value adjustment | (9 | ) | | (9 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Discrete impacts from EIMA (c) | (36 | ) | | — |
| | (36 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of debt costs | 26 |
| | 12 |
| | (3 | ) | | 2 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Provision for excess and obsolete inventory
| 74 |
| | 70 |
| | 4 |
| | — |
| | — |
| | 1 |
| | 1 |
| | 1 |
| | — |
| | | 1 |
|
Merger-related commitments (d)(e) | 508 |
| | 3 |
| | — |
| | — |
| | — |
| | 125 |
| | 73 |
| | 110 |
| | 308 |
| | | — |
|
Severance costs | 130 |
| | 57 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 53 |
| | | — |
|
Asset retirement costs | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| | 2 |
| | — |
| | | — |
|
Lower of cost or net realizable value inventory adjustment | 36 |
| | 36 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Other | 15 |
| | 24 |
| | (1 | ) | | (3 | ) | | (18 | ) | | (2 | ) | | (8 | ) | | (5 | ) | | (7 | ) | | | (3 | ) |
Total other non-cash operating activities | $ | 1,224 |
|
| $ | 129 |
|
| $ | 122 |
|
| $ | 49 |
|
| $ | 109 |
| | $ | 168 |
|
| $ | 99 |
|
| $ | 138 |
| | $ | 441 |
| | | $ | 46 |
|
Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | | | | |
Change in capital expenditures not paid | $ | (338 | ) | | $ | (289 | ) | | $ | (42 | ) | | $ | (4 | ) | | $ | 17 |
| | $ | 15 |
| | $ | (10 | ) | | $ | 2 |
| | $ | (5 | ) | | | $ | 11 |
|
Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash(d)(f) | — |
| | 119 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash(d)(f) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 129 |
| | | — |
|
Fair value of pension obligation transferred in connection with the PHI Merger | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 53 |
| | | — |
|
Assumption of member purchase liability | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 29 |
| | | — |
|
Assumption of merger commitment liability | — |
| | — |
| | — |
| | — |
| | — |
| | 33 |
| | — |
| | — |
| | 33 |
| | | — |
|
Change in PPE related to ARO update
| 476 |
| | 476 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Indemnification of like-kind exchange position(g) | — |
| | — |
| | 157 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Non-cash financing of capital projects | 84 |
| | 84 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Dividends on stock compensation | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
_________
| |
(a) | Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 16 - Asset Retirement Obligations of the Exelon 2016 Form 10-K for additional information regarding the accounting for nuclear decommissioning. |
| |
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
| |
(c) | Reflects the change in distribution rates pursuant to EIMA and FEJA, which allows for the recovery of distribution costs by a utility through a pre-established performance-based formula rate tariff. Beginning June 1, 2017, also reflects the change in energy efficiency rates pursuant to FEJA, which allows for the recovery of energy efficiency costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information. |
| |
(d) | See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI. |
| |
(e) | Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts. |
| |
(f) | Immediately following closing of the PHI Merger, the net assets associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation. |
| |
(g) | See Note 12— Income Taxes for discussion of the like-kind exchange tax position. |
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2017 and December 31, 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
September 30, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Property, plant and equipment: | | | | | | | | | | | | | | | | | |
Accumulated depreciation and amortization | $ | 20,591 |
| (a) | $ | 11,193 |
| (a) | $ | 4,191 |
|
| $ | 3,366 |
|
| $ | 3,351 |
| | $ | 448 |
| | $ | 3,171 |
|
| $ | 1,231 |
|
| $ | 1,060 |
|
Accounts receivable: | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | $ | 339 |
|
| $ | 111 |
|
| $ | 72 |
|
| $ | 57 |
|
| $ | 25 |
| | $ | 74 |
| | $ | 29 |
|
| $ | 17 |
|
| $ | 28 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | |
| | | | |
December 31, 2016 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Property, plant and equipment: | | | | | | | | | | | | | | | | | |
Accumulated depreciation and amortization | $ | 19,169 |
| (b) | $ | 10,562 |
| (b) | $ | 3,937 |
|
| $ | 3,253 |
|
| $ | 3,254 |
| | $ | 195 |
| | $ | 3,050 |
|
| $ | 1,175 |
|
| $ | 1,016 |
|
Accounts receivable: | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | $ | 334 |
|
| $ | 91 |
| | $ | 70 |
|
| $ | 61 |
|
| $ | 32 |
| | $ | 80 |
| | $ | 29 |
|
| $ | 24 |
|
| $ | 27 |
|
_________
| |
(a) | Includes accumulated amortization of nuclear fuel in the reactor core of $3,303 million. |
| |
(b) | Includes accumulated amortization of nuclear fuel in the reactor core of $3,186 million. |
PECO Installment Plan Receivables (Exelon and PECO)
PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $11 million and $9 million as of September 30, 2017 and December 31, 2016, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2016 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2017 of $12 million consists of $3 million and $9 million for medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2016 of $13 million consists of $1 million, $3 million and $9 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of September 30, 2017 and December 31, 2016 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2016 Form 10-K.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
20. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.
In the first quarter of 2016, following the consummation of the PHI Merger, three new reportable segments were added: Pepco, DPL and ACE. As a result, Exelon has twelve reportable segments, which include ComEd, PECO, BGE, PHI's three reportable segments consisting of Pepco, DPL, and ACE, and Generation’s sixreportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income and return on equity.
Effective with the consummation of the PHI Merger, PHI's reportable segments have changed based on the information used by the CODM to evaluate performance and allocate resources. PHI's reportable segments consist of Pepco, DPL and ACE. PHI's Predecessor periods' segment information has been recast to conform to the current presentation. The reclassification of the segment information did not impact PHI's reported consolidated revenues or net income. PHI's CODM evaluates the performance of and allocates resources to Pepco, DPL and ACE based on net income and return on equity.
The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:
Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.
Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.
New York represents operations within ISO-NY, which covers the state of New York in its entirety.
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on revenues net of purchased power and fuel expense (RNF). Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2017 and 2016 is as follows:
Three Months Ended September 30, 2017 and 2016
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
| Generation(a) | | ComEd | | PECO | | BGE | | PHI(b) | | Other(c) | | Intersegment Eliminations | | Exelon |
Operating revenues(d): | | | | | | | | | | | | | | | |
2017 | | | | | | | | | | | | | | | |
Competitive businesses electric revenues | $ | 4,042 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (295 | ) | | $ | 3,747 |
|
Competitive businesses natural gas revenues | 460 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 460 |
|
Competitive businesses other revenues | 249 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 249 |
|
Rate-regulated electric revenues | — |
| | 1,571 |
| | 662 |
| | 658 |
| | 1,280 |
| | — |
| | (7 | ) | | 4,164 |
|
Rate-regulated natural gas revenues | — |
| | — |
| | 53 |
| | 80 |
| | 18 |
| | — |
| | (2 | ) | | 149 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 12 |
| | 446 |
| | (458 | ) | | — |
|
2016 | | | | | | | | | | | | | | | |
Competitive businesses electric revenues | $ | 4,322 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (499 | ) | | $ | 3,823 |
|
Competitive businesses natural gas revenues | 326 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 326 |
|
Competitive businesses other revenues | 387 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 386 |
|
Rate-regulated electric revenues | — |
| | 1,497 |
| | 740 |
| | 735 |
| | 1,366 |
| | — |
| | (8 | ) | | 4,330 |
|
Rate-regulated natural gas revenues | — |
| | — |
| | 48 |
| | 77 |
| | 17 |
| | — |
| | (5 | ) | | 137 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 11 |
| | 362 |
| | (373 | ) | | — |
|
Intersegment revenues(e): | | | | | | | | | | | | | | | |
2017 | $ | 294 |
| | $ | 3 |
| | $ | 2 |
| | $ | 3 |
| | $ | 12 |
| | $ | 445 |
| | $ | (759 | ) | | $ | — |
|
2016 | 500 |
| | 4 |
| | 2 |
| | 7 |
| | 11 |
| | 362 |
| | (885 | ) | | 1 |
|
Net income (loss): | | | | | | | | | | | | | | |
|
2017 | $ | 348 |
| | $ | 189 |
| | $ | 112 |
| | $ | 62 |
| | $ | 153 |
| | $ | 3 |
| | $ | — |
| | $ | 867 |
|
2016 | 271 |
| | 37 |
| | 122 |
| | 56 |
| | 166 |
| | (125 | ) | | (1 | ) | | 526 |
|
Total assets: | | | | | | | | | | | | | | |
|
September 30, 2017 | $ | 47,744 |
| | $ | 29,649 |
| | $ | 11,480 |
| | $ | 8,923 |
| | $ | 21,301 |
| | $ | 10,662 |
| | $ | (11,286 | ) | | $ | 118,473 |
|
December 31, 2016 | 46,974 |
| | 28,335 |
| | 10,831 |
| | 8,704 |
| | 21,025 |
| | 10,369 |
| | (11,334 | ) | | 114,904 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
_________
| |
(a) | Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended September 30, 2017 include revenue from sales to PECO of $31 million, sales to BGE of $98 million, sales to Pepco of $57 million, sales to DPL of $47 million, and sales to ACE of $7 million in the Mid-Atlantic region, and sales to ComEd of $54 million in the Midwest region. For the three months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $91 million, sales to BGE of $183 million, sales to Pepco of $128 million, sales to DPL of $63 million, and sales to ACE of $15 million in the Mid-Atlantic region, and sales to ComEd of $20 million in the Midwest region. |
| |
(b) | Amounts included represent activity for PHI's successor period, three months ended September 30, 2017 and 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. |
| |
(c) | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. |
| |
(d) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2017 and 2016. |
| |
(e) | Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. |
Successor PHI:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE | | Other(b) | | Intersegment Eliminations | | PHI |
Operating revenues(a): |
Three Months Ended September 30, 2017 - Successor | | | | | | | | | | | |
Rate-regulated electric revenues | $ | 604 |
| | $ | 309 |
| | $ | 370 |
| | $ | — |
| | $ | (3 | ) | | $ | 1,280 |
|
Rate-regulated natural gas revenues | — |
| | 18 |
| | — |
| | — |
| | — |
| | 18 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | 12 |
| | — |
| | 12 |
|
Three Months Ended September 30, 2016 - Successor | | | | | | | | | | | |
Rate-regulated electric revenues | $ | 635 |
| | $ | 314 |
| | $ | 421 |
| | $ | — |
| | $ | (4 | ) | | $ | 1,366 |
|
Rate-regulated natural gas revenues | — |
| | 17 |
| | — |
| | — |
| | — |
| | 17 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | 11 |
| | — |
| | 11 |
|
Intersegment revenues: | | | | | | | | | | | |
Three Months Ended September 30, 2017 - Successor | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | 13 |
| | $ | (4 | ) | | $ | 12 |
|
Three Months Ended September 30, 2016 - Successor | 1 |
| | 2 |
| | 1 |
| | 11 |
| | (4 | ) | | 11 |
|
Net income (loss): | | | | | | | | | | | |
Three Months Ended September 30, 2017 - Successor | $ | 87 |
| | $ | 31 |
| | $ | 41 |
| | $ | (18 | ) | | $ | 12 |
| | $ | 153 |
|
Three Months Ended September 30, 2016 - Successor | 79 |
| | 44 |
| | 47 |
| | (15 | ) | | 11 |
| | 166 |
|
Total assets: | | | | | | | | | | | |
September 30, 2017 - Successor | $ | 7,775 |
| | $ | 4,276 |
| | $ | 3,510 |
| | $ | 10,724 |
| | $ | (4,984 | ) | | $ | 21,301 |
|
December 31, 2016 - Successor | 7,335 |
| | 4,153 |
| | 3,457 |
| | 10,804 |
| | (4,724 | ) | | 21,025 |
|
_________
| |
(a) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2017 and 2016. |
| |
(b) | Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation total revenues:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 |
| Revenues from external customers(a) |
| Intersegment revenues |
| Total Revenues |
| Revenues from external customers(a) |
| Intersegment revenues |
| Total Revenues |
Mid-Atlantic | $ | 1,421 |
| | $ | 11 |
| | $ | 1,432 |
| | $ | 1,813 |
| | $ | (13 | ) | | $ | 1,800 |
|
Midwest | 1,049 |
| | (11 | ) | | 1,038 |
| | 1,163 |
| | 1 |
| | 1,164 |
|
New England | 482 |
| | (1 | ) | | 481 |
| | 455 |
| | (4 | ) | | 451 |
|
New York | 434 |
| | (6 | ) | | 428 |
| | 331 |
| | (8 | ) | | 323 |
|
ERCOT | 308 |
| | 6 |
| | 314 |
| | 289 |
| | 6 |
| | 295 |
|
Other Power Regions | 348 |
| | (13 | ) | | 335 |
| | 271 |
| | (33 | ) | | 238 |
|
Total Revenues for Reportable Segments | 4,042 |
| | (14 | ) | | 4,028 |
| | 4,322 |
| | (51 | ) | | 4,271 |
|
Other(b) | 709 |
| | 14 |
| | 723 |
| | 713 |
| | 51 |
| | 764 |
|
Total Generation Consolidated Operating Revenues | $ | 4,751 |
| | $ | — |
| | $ | 4,751 |
| | $ | 5,035 |
| | $ | — |
| | $ | 5,035 |
|
_________ | |
(a) | Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants. |
| |
(b) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $13 million and $21 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market gain of $52 million and $187 million for the three months ended September 30, 2017 and 2016, respectively, and elimination of intersegment revenues. |
Generation total revenues net of purchased power and fuel expense:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 |
| RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF |
Mid-Atlantic | $ | 817 |
| | $ | 38 |
| | $ | 855 |
| | $ | 881 |
| | $ | 6 |
| | $ | 887 |
|
Midwest | 697 |
| | — |
| | 697 |
| | 782 |
| | (1 | ) | | 781 |
|
New England | 151 |
| | (6 | ) | | 145 |
| | 170 |
| | (10 | ) | | 160 |
|
New York | 296 |
| | — |
| | 296 |
| | 195 |
| | (1 | ) | | 194 |
|
ERCOT | 229 |
| | (111 | ) | | 118 |
| | 144 |
| | (51 | ) | | 93 |
|
Other Power Regions | 118 |
| | (50 | ) | | 68 |
| | 143 |
| | (66 | ) | | 77 |
|
Total Revenues net of purchased power and fuel for Reportable Segments | 2,308 |
|
| (129 | ) |
| 2,179 |
|
| 2,315 |
|
| (123 | ) |
| 2,192 |
|
Other(b) | 112 |
| | 129 |
| | 241 |
| | 131 |
| | 123 |
| | 254 |
|
Total Generation Revenues net of purchased power and fuel expense | $ | 2,420 |
|
| $ | — |
|
| $ | 2,420 |
|
| $ | 2,446 |
|
| $ | — |
|
| $ | 2,446 |
|
_________
| |
(a) | Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants. |
| |
(b) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $19 million and $22 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market gains of $73 million and $88 million for the three months ended September 30, 2017 and 2016, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $6 million and $28 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2017 and 2016
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
| Generation(a) | | ComEd | | PECO | | BGE | | PHI(b) | | Other(c) | | Intersegment Eliminations | | Exelon |
Operating revenues(d): |
2017 | | | | | | | | | | | | | | | |
Competitive businesses electric revenues | $ | 11,485 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (888 | ) | | $ | 10,597 |
|
Competitive businesses natural gas revenues | 1,807 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,807 |
|
Competitive businesses other revenues | 520 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 520 |
|
Rate-regulated electric revenues | — |
| | 4,227 |
| | 1,802 |
| | 1,895 |
| | 3,417 |
| | — |
| | (23 | ) | | 11,318 |
|
Rate-regulated natural gas revenues | — |
| | — |
| | 339 |
| | 468 |
| | 105 |
| | — |
| | (6 | ) | | 906 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 35 |
| | 1,316 |
| | (1,350 | ) | | 1 |
|
2016 | | | | | | | | | | | | | | | |
Competitive businesses electric revenues | $ | 11,677 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,118 | ) | | $ | 10,559 |
|
Competitive businesses natural gas revenues | 1,515 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,515 |
|
Competitive businesses other revenues | 171 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | | 169 |
|
Rate-regulated electric revenues | — |
| | 4,031 |
| | 1,971 |
| | 1,998 |
| | 2,485 |
| | — |
| | (24 | ) | | 10,461 |
|
Rate-regulated natural gas revenues | — |
| | — |
| | 322 |
| | 423 |
| | 46 |
| | — |
| | (10 | ) | | 781 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 34 |
| | 1,166 |
| | (1,199 | ) | | 1 |
|
Intersegment revenues(e): | | | | | | | | | | | | | | | |
2017 | $ | 888 |
| | $ | 12 |
| | $ | 5 |
| | $ | 12 |
| | $ | 35 |
| | $ | 1,312 |
| | $ | (2,262 | ) | | $ | 2 |
|
2016 | 1,121 |
| | 12 |
| | 5 |
| | 16 |
| | 34 |
| | 1,166 |
| | (2,351 | ) | | 3 |
|
Net income (loss): | | | | | | | | | | | | | | | |
2017 | $ | 491 |
| | $ | 447 |
| | $ | 327 |
| | $ | 231 |
| | $ | 359 |
| | $ | 58 |
| | $ | (2 | ) | | $ | 1,911 |
|
2016 | 556 |
| | 297 |
| | 346 |
| | 191 |
| | (91 | ) | | (340 | ) | | (3 | ) | | 956 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
_________
| |
(a) | Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the nine months ended September 30, 2017 include revenue from sales to PECO of $111 million, sales to BGE of $330 million, sales to Pepco of $209 million, sales to DPL of $138 million, and sales to ACE of $23 million in the Mid-Atlantic region, and sales to ComEd of $77 million in the Midwest region. For the nine months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $234 million and sales to BGE of $489 million in the Mid-Atlantic region, and sales to ComEd of $38 million in the Midwest region. For the Successor period of March 24, 2016 to September 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $223 million, sales to DPL of $109 million, and sales to ACE of $28 million in the Mid-Atlantic region. |
| |
(b) | Amounts included represent activity for PHI's successor period, nine months ended September 30, 2017 and March 24, 2016 through September 30, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor period, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016. |
| |
(c) | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. |
| |
(d) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2017 and 2016. |
| |
(e) | Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. |
Successor and Predecessor PHI:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE | | Other(b) | | Intersegment Eliminations | | PHI |
Operating revenues(a): | | | | | | | | | | | |
Nine Months Ended September 30, 2017 - Successor | | | | | | | | | | | |
Rate-regulated electric revenues | $ | 1,649 |
| | $ | 866 |
| | $ | 915 |
| | $ | — |
| | $ | (13 | ) | | $ | 3,417 |
|
Rate-regulated natural gas revenues | — |
| | 105 |
| | — |
| | — |
| | — |
| | 105 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | 37 |
| | (2 | ) | | 35 |
|
March 24, 2016 to September 30, 2016 - Successor | | | | | | | | | | | |
Rate-regulated electric revenues | $ | 1,184 |
| | $ | 593 |
| | $ | 714 |
| | $ | 3 |
| | $ | (9 | ) | | $ | 2,485 |
|
Rate-regulated natural gas revenues | — |
| | 46 |
| | — |
| | — |
| | — |
| | 46 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | 34 |
| | — |
| | 34 |
|
January 1, 2016 to March 23, 2016 - Predecessor | | | | | | | | | | | |
Rate-regulated electric revenues | $ | 511 |
| | $ | 279 |
| | $ | 268 |
| | $ | 42 |
| | $ | (4 | ) | | $ | 1,096 |
|
Rate-regulated natural gas revenues | — |
| | 56 |
| | — |
| | 1 |
| | — |
| | 57 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Intersegment revenues: | | | | | | | | | | | |
Nine Months Ended September 30, 2017 - Successor | $ | 4 |
| | $ | 6 |
| | $ | 2 |
| | $ | 37 |
| | $ | (14 | ) | | $ | 35 |
|
March 24, 2016 to September 30, 2016 - Successor | 2 |
| | 4 |
| | 2 |
| | 35 |
| | (9 | ) | | 34 |
|
January 1, 2016 to March 23, 2016 - Predecessor | 1 |
| | 2 |
| | 1 |
| | — |
| | (4 | ) | | — |
|
Net income (loss): | | | | | | | | | | | |
Nine Months Ended September 30, 2017 - Successor | $ | 188 |
| | $ | 107 |
| | $ | 77 |
| | $ | (48 | ) | | $ | 35 |
| | $ | 359 |
|
March 24, 2016 to September 30, 2016 - Successor | (12 | ) | | (42 | ) | | (55 | ) | | (16 | ) | | 34 |
| | (91 | ) |
January 1, 2016 to March 23, 2016 - Predecessor | 32 |
| | 26 |
| | 5 |
| | (44 | ) | | — |
| | 19 |
|
_________
| |
(a) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2017 and 2016. |
| |
(b) | Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor period presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation total revenues:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 | | Nine Months Ended September 30, 2016 |
| Revenues from external customers(a) | | Intersegment revenues | | Total Revenues | | Revenues from external customers(a) | | Intersegment revenues | | Total Revenues |
Mid-Atlantic | $ | 4,207 |
| | $ | 15 |
| | $ | 4,222 |
| | $ | 4,776 |
| | $ | (40 | ) | | $ | 4,736 |
|
Midwest | 3,158 |
| | (17 | ) | | 3,141 |
| | 3,330 |
| | 13 |
| | 3,343 |
|
New England | 1,469 |
| | (8 | ) | | 1,461 |
| | 1,278 |
| | (6 | ) | | 1,272 |
|
New York | 1,095 |
| | (14 | ) | | 1,081 |
| | 906 |
| | (33 | ) | | 873 |
|
ERCOT | 749 |
| | 4 |
| | 753 |
| | 659 |
| | 6 |
| | 665 |
|
Other Power Regions | 807 |
| | (28 | ) | | 779 |
| | 728 |
| | (42 | ) | | 686 |
|
Total Revenues for Reportable Segments | 11,485 |
|
| (48 | ) |
| 11,437 |
|
| 11,677 |
|
| (102 | ) |
| 11,575 |
|
Other(b) | 2,327 |
| | 48 |
| | 2,375 |
| | 1,686 |
| | 102 |
| | 1,788 |
|
Total Generation Consolidated Operating Revenues | $ | 13,812 |
|
| $ | — |
|
| $ | 13,812 |
|
| $ | 13,363 |
|
| $ | — |
|
| $ | 13,363 |
|
_________
| |
(a) | Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants. |
| |
(b) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $30 million and $10 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the nine months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market losses of $47 million and $366 million for the nine months ended September 30, 2017 and 2016, respectively, and elimination of intersegment revenues. |
Generation total revenues net of purchased power and fuel expense:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 | | Nine Months Ended September 30, 2016 |
| RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF |
Mid-Atlantic | $ | 2,330 |
| | $ | 81 |
| | $ | 2,411 |
| | $ | 2,541 |
| | $ | 15 |
| | $ | 2,556 |
|
Midwest | 2,129 |
| | 11 |
| | 2,140 |
| | 2,225 |
| | 4 |
| | 2,229 |
|
New England | 423 |
| | (20 | ) | | 403 |
| | 373 |
| | (23 | ) | | 350 |
|
New York | 679 |
| | (1 | ) | | 678 |
| | 607 |
| | (15 | ) | | 592 |
|
ERCOT | 446 |
| | (188 | ) | | 258 |
| | 335 |
| | (104 | ) | | 231 |
|
Other Power Regions | 359 |
| | (139 | ) | | 220 |
| | 357 |
| | (104 | ) | | 253 |
|
Total Revenues net of purchased power and fuel expense for Reportable Segments | 6,366 |
|
| (256 | ) |
| 6,110 |
|
| 6,438 |
|
| (227 | ) |
| 6,211 |
|
Other(b) | 160 |
| | 256 |
| | 416 |
| | 316 |
| | 227 |
| | 543 |
|
Total Generation Revenues net of purchased power and fuel expense | $ | 6,526 |
|
| $ | — |
|
| $ | 6,526 |
|
| $ | 6,754 |
|
| $ | — |
|
| $ | 6,754 |
|
_________
| |
(a) | Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants. |
| |
(b) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $41 million and $15 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the nine months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market losses of $161 million and $113 million for the nine months ended September 30, 2017 and 2016, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $8 million and $38 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense. |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other, Net |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Three Months Ended March 31, 2023 | | | | | | | | | | | | | | | |
AFUDC — Equity | $ | 38 | | | $ | 10 | | | $ | 6 | | | $ | 3 | | | $ | 19 | | | $ | 14 | | | $ | 2 | | | $ | 3 | |
Non-service net periodic benefit cost | (1) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Three Months Ended March 31, 2022 | | | | | | | | | | | | | | | |
AFUDC — Equity | $ | 36 | | | $ | 8 | | | $ | 7 | | | $ | 6 | | | $ | 15 | | | $ | 11 | | | $ | 2 | | | $ | 2 | |
Non-service net periodic benefit cost | 17 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Depreciation, amortization, and accretion |
| Exelon(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Three Months Ended March 31, 2023 | | | | | | | | | | | | | | | |
Property, plant, and equipment(b) | $ | 680 | | | $ | 267 | | | $ | 95 | | | $ | 124 | | | $ | 180 | | | $ | 76 | | | $ | 51 | | | $ | 47 | |
Amortization of regulatory assets(b) | 178 | | | 71 | | | 3 | | | 43 | | | 61 | | | 32 | | | 9 | | | 20 | |
Amortization of intangible assets, net(b) | 2 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Total depreciation and amortization | $ | 860 | | | $ | 338 | | | $ | 98 | | | $ | 167 | | | $ | 241 | | | $ | 108 | | | $ | 60 | | | $ | 67 | |
| | | | | | | | | | | | | | | |
Three Months Ended March 31, 2022 | | | | | | | | | | | | | | | |
Property, plant, and equipment(b) | $ | 726 | | | $ | 254 | | | $ | 88 | | | $ | 117 | | | $ | 164 | | | $ | 72 | | | $ | 45 | | | $ | 41 | |
Amortization of regulatory assets(b) | 179 | | | 67 | | | 4 | | | 54 | | | 54 | | | 36 | | | 12 | | | 6 | |
Amortization of intangible assets, net(b) | 6 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Amortization of energy contract assets and liabilities(c) | 3 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Nuclear fuel(d) | 66 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
ARO accretion(e) | 44 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Total depreciation, amortization, and accretion | $ | 1,024 | | | $ | 321 | | | $ | 92 | | | $ | 171 | | | $ | 218 | | | $ | 108 | | | $ | 57 | | | $ | 47 | |
__________
(a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
(b)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Electric operating revenues or Purchased power expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.
(d)Included in Purchased fuel expense in Exelon's Consolidated Statement of Operations and Comprehensive Income.
(e)Included in Operating and maintenance expense in Exelon's Consolidated Statement of Operations and Comprehensive Income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other non-cash operating activities |
| Exelon(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Three Months Ended March 31, 2023 | | | | | | | | | | | | | | | |
Pension and OPEB costs (benefit) | $ | 45 | | | $ | 6 | | | $ | (3) | | | $ | 14 | | | $ | 24 | | | $ | 8 | | | $ | 4 | | | $ | 4 | |
Allowance for credit losses | 70 | | | — | | | 37 | | | 18 | | | 15 | | | 7 | | | 5 | | | 3 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
True-up adjustments to decoupling mechanisms and formula rates(b) | (282) | | | (153) | | | 4 | | | (65) | | | (68) | | | (39) | | | (11) | | | (18) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Long-term incentive plan | 2 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Amortization of operating ROU asset | 10 | | | 1 | | | — | | | 1 | | | 7 | | | 1 | | | 2 | | | 1 | |
Change in environmental liabilities | 25 | | | — | | | — | | | — | | | 25 | | | 25 | | | — | | | — | |
| | | | | | | | | | | | | | | |
AFUDC — Equity | (38) | | | (10) | | | (6) | | | (3) | | | (19) | | | (14) | | | (2) | | | (3) | |
| | | | | | | | | | | | | | | |
Three Months Ended March 31, 2022 | | | | | | | | | | | | | | | |
Pension and OPEB costs (benefit) | $ | 44 | | | $ | 16 | | | $ | (2) | | | $ | 12 | | | $ | 13 | | | $ | 2 | | | $ | 1 | | | $ | 3 | |
Allowance for credit losses | 78 | | | 17 | | | 27 | | | 18 | | | 18 | | | 9 | | | 6 | | | 3 | |
Other decommissioning-related activity | 36 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Energy-related options | 60 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
True-up adjustments to decoupling mechanisms and formula rates(b) | (29) | | | (40) | | | (6) | | | 12 | | | 5 | | | 7 | | | 1 | | | (3) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Long-term incentive plan | 25 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Amortization of operating ROU asset | 23 | | | 1 | | | — | | | 7 | | | 7 | | | 2 | | | 2 | | | 1 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
AFUDC — Equity | (36) | | | (8) | | | (7) | | | (6) | | | (15) | | | (11) | | | (2) | | | (2) | |
__________
(a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.
(b)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters of the 2022 Form 10-K for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Supplemental Financial Information
The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
March 31, 2023 | | | | | | | | | | | | | | | |
Cash and cash equivalents | $ | 522 | | | $ | 75 | | | $ | 27 | | | $ | 20 | | | $ | 367 | | | $ | 126 | | | $ | 142 | | | $ | 71 | |
Restricted cash and cash equivalents | 381 | | | 323 | | | 9 | | | 1 | | | 29 | | | 27 | | | 1 | | | — | |
Restricted cash included in other deferred debits and other assets | 180 | | | 180 | | | — | | | — | | | — | | | — | | | — | | | — | |
Total cash, restricted cash, and cash equivalents | $ | 1,083 | | | $ | 578 | | | $ | 36 | | | $ | 21 | | | $ | 396 | | | $ | 153 | | | $ | 143 | | | $ | 71 | |
| | | | | | | | | | | | | | | |
December 31, 2022 | | | | | | | | | | | | | | | |
Cash and cash equivalents | $ | 407 | | | $ | 67 | | | $ | 59 | | | $ | 43 | | | $ | 198 | | | $ | 45 | | | $ | 31 | | | $ | 72 | |
Restricted cash and cash equivalents | 566 | | | 327 | | | 9 | | | 24 | | | 175 | | | 54 | | | 121 | | | — | |
Restricted cash included in other deferred debits and other assets | 117 | | | 117 | | | — | | | — | | | — | | | — | | | — | | | — | |
Total cash, restricted cash, and cash equivalents | $ | 1,090 | | | $ | 511 | | | $ | 68 | | | $ | 67 | | | $ | 373 | | | $ | 99 | | | $ | 152 | | | $ | 72 | |
| | | | | | | | | | | | | | | |
March 31, 2022 | | | | | | | | | | | | | | | |
Cash and cash equivalents | $ | 2,476 | | | $ | 343 | | | $ | 26 | | | $ | 41 | | | $ | 796 | | | $ | 502 | | | $ | 120 | | | $ | 168 | |
Restricted cash and cash equivalents | 430 | | | 246 | | | 8 | | | 34 | | | 106 | | | 34 | | | 73 | | | — | |
Restricted cash included in other deferred debits and other assets | 92 | | | 92 | | | — | | | — | | | — | | | — | | | — | | | — | |
Total cash, restricted cash, and cash equivalents | $ | 2,998 | | | $ | 681 | | | $ | 34 | | | $ | 75 | | | $ | 902 | | | $ | 536 | | | $ | 193 | | | $ | 168 | |
| | | | | | | | | | | | | | | |
December 31, 2021 | | | | | | | | | | | | | | | |
Cash and cash equivalents | $ | 672 | | | $ | 131 | | | $ | 36 | | | $ | 51 | | | $ | 136 | | | $ | 34 | | | $ | 28 | | | $ | 29 | |
Restricted cash and cash equivalents | 321 | | | 210 | | | 8 | | | 4 | | | 77 | | | 34 | | | 43 | | | — | |
Restricted cash included in other deferred debits and other assets | 44 | | | 43 | | | — | | | — | | | — | | | — | | | — | | | — | |
Cash, restricted cash, and cash equivalents from discontinued operations | 582 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Total cash, restricted cash, and cash equivalents | $ | 1,619 | | | $ | 384 | | | $ | 44 | | | $ | 55 | | | $ | 213 | | | $ | 68 | | | $ | 71 | | | $ | 29 | |
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2022 Form 10-K.
Supplemental Balance Sheet Information
The following table provides additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued expenses |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
March 31, 2023 | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 359 | | | $ | 107 | | | $ | 43 | | | $ | 42 | | | $ | 59 | | | $ | 18 | | | $ | 11 | | | $ | 10 | |
Taxes accrued | 214 | | | 102 | | | 3 | | | 83 | | | 94 | | | 67 | | | 14 | | | 16 | |
Interest accrued | 373 | | | 78 | | | 44 | | | 45 | | | 75 | | | 35 | | | 22 | | | 16 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
December 31, 2022 | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 613 | | | $ | 179 | | | $ | 81 | | | $ | 79 | | | $ | 104 | | | $ | 29 | | | $ | 20 | | | $ | 16 | |
Taxes accrued | 211 | | | 92 | | | 10 | | | 34 | | | 70 | | | 52 | | | 8 | | | 12 | |
Interest accrued | 338 | | | 124 | | | 47 | | | 42 | | | 61 | | | 32 | | | 9 | | | 14 | |
__________
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
16. Related Party Transactions (All Registrants)
Utility Registrants' expense with Generation
The Utility Registrants incurred expenses from transactions with the Generation affiliate as described in the footnotes to the table below prior to separation on February 1, 2022. Such expenses were primarily recorded as Purchased power from affiliate and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. Effective February 1, 2022, Generation is no longer considered a related party.
| | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | | | |
ComEd(a) | $ | 59 | | | | | |
PECO(b) | 33 | | | | | |
BGE(c) | 18 | | | | | |
PHI | 51 | | | | | |
Pepco(d) | 39 | | | | | |
DPL(e) | 10 | | | | | |
ACE(f) | 2 | | | | | |
__________(a)ComEd had an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Generation.
(b)PECO received electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Generation to sell solar AECs.
(c)BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.
(d)Pepco received electric supply from Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
(e)DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.
(f)ACE received electric supply from Generation under contracts executed through ACE's competitive procurement process approved by the NJBPU.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 16 — Related Party Transactions
Service Company Costs for Corporate Support
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 — Significant Accounting Policies for additional information regarding BSC and PHISCO.
The following table presents the service company costs allocated to the Registrants:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Operating and maintenance from affiliates | | Capitalized costs |
| | Three Months Ended March 31, | | | | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | | | 2023 | | 2022 | | | | |
Exelon | | | | | | | | | | | | | | | | |
BSC | | | | | | | | | | $ | 175 | | | $ | 205 | | | | | |
PHISCO | | | | | | | | | | 24 | | | 19 | | | | | |
ComEd | | | | | | | | | | | | | | | | |
BSC | | $ | 83 | | | $ | 85 | | | | | | | 81 | | | 85 | | | | | |
PECO | | | | | | | | | | | | | | | | |
BSC | | 51 | | | 49 | | | | | | | 30 | | | 36 | | | | | |
BGE | | | | | | | | | | | | | | | | |
BSC | | 54 | | | 51 | | | | | | | 24 | | | 38 | | | | | |
PHI | | | | | | | | | | | | | | | | |
BSC | | 42 | | | 50 | | | | | | | 40 | | | 46 | | | | | |
PHISCO | | — | | | — | | | | | | | 24 | | | 19 | | | | | |
Pepco | | | | | | | | | | | | | | | | |
BSC | | 27 | | | 29 | | | | | | | 14 | | | 17 | | | | | |
PHISCO | | 30 | | | 29 | | | | | | | 11 | | | 8 | | | | | |
| | | | | | | | | | | | | | | | |
DPL | | | | | | | | | | | | | | | | |
BSC | | 17 | | | 18 | | | | | | | 10 | | | 14 | | | | | |
PHISCO | | 24 | | | 24 | | | | | | | 7 | | | 6 | | | | | |
| | | | | | | | | | | | | | | | |
ACE | | | | | | | | | | | | | | | | |
BSC | | 14 | | | 15 | | | | | | | 14 | | | 15 | | | | | |
PHISCO | | 22 | | | 21 | | | | | | | 6 | | | 5 | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 16 — Related Party Transactions
Current Receivables from/Payables to affiliates
The following tables present current Receivables from affiliates and current Payables to affiliates:
March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Receivables from affiliates: | | |
| Payables to affiliates: | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE | | BSC | | PHISCO | | Other | | Total |
ComEd | | | | $ | — | | | $ | — | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 78 | | | $ | — | | | $ | 6 | | | $ | 84 | |
PECO | | $ | — | | | | | — | | | | | — | | | — | | | 1 | | | 39 | | | — | | | 8 | | | 48 | |
BGE | | — | | | — | | | | | | | — | | | — | | | — | | | 35 | | | — | | | 2 | | | 37 | |
PHI | | — | | | — | | | — | | | | | — | | | — | | | — | | | 7 | | | — | | | 10 | | | 17 | |
Pepco | | — | | | — | | | — | | | | | | | — | | | — | | | 22 | | | 15 | | | 1 | | | 38 | |
DPL | | — | | | 1 | | | — | | | | | — | | | | | — | | | 13 | | | 12 | | | — | | | 26 | |
ACE | | — | | | 1 | | | — | | | | | 1 | | | — | | | | | 13 | | | 11 | | | — | | | 26 | |
Other | | 3 | | | — | | | — | | | | | — | | | — | | | 1 | | | — | | | 1 | | | | | 5 | |
Total | | $ | 3 | | | $ | 2 | | | $ | — | | | | | $ | 1 | | | $ | — | | | $ | 2 | | | $ | 207 | | | $ | 39 | | | $ | 27 | | | $ | 281 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Receivables from affiliates: | | |
| Payables to affiliates: | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE | | BSC | | PHISCO | | Other | | Total |
ComEd | | | | $ | — | | | $ | — | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 66 | | | $ | — | | | $ | 8 | | | $ | 74 | |
PECO | | $ | — | | | | | — | | | | | — | | | — | | | — | | | 39 | | | — | | | 3 | | | 42 | |
BGE | | — | | | — | | | | | | | — | | | — | | | — | | | 38 | | | — | | | 1 | | | 39 | |
PHI | | — | | | — | | | — | | | | | — | | | — | | | — | | | 4 | | | — | | | 10 | | | 14 | |
Pepco | | — | | | — | | | — | | | | | | | — | | | — | | | 20 | | | 13 | | | 1 | | | 34 | |
DPL | | — | | | 2 | | | — | | | | | — | | | | | — | | | 12 | | | 8 | | | — | | | 22 | |
ACE | | — | | | 2 | | | — | | | | | — | | | — | | | | | 14 | | | 9 | | | 1 | | | 26 | |
Other | | 3 | | | — | | | — | | | | | — | | | — | | | 1 | | | — | | | — | | | | | 4 | |
Total | | $ | 3 | | | $ | 4 | | | $ | — | | | | | $ | — | | | $ | — | | | $ | 1 | | | $ | 193 | | | $ | 30 | | | $ | 24 | | | $ | 255 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
Borrowings from Exelon/PHI intercompany money pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. PECO and PHI Corporate participate in the Exelon intercompany money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2023 | | December 31, 2022 |
| Exelon | | ComEd | | PECO | | Exelon | | ComEd | | PECO |
ComEd Financing III | $ | 206 | | | $ | 205 | | | $ | — | | | $ | 206 | | | $ | 205 | | | $ | — | |
PECO Trust III | 81 | | | — | | | 81 | | | 81 | | | — | | | 81 | |
PECO Trust IV | 103 | | | — | | | 103 | | | 103 | | | — | | | 103 | |
Total | $ | 390 | | | $ | 205 | | | $ | 184 | | | $ | 390 | | | $ | 205 | | | $ | 184 | |
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions except per share data, unless otherwise noted)
Exelon
Executive Overview
Exelon a utility services holding company, operates through the following principal subsidiaries:
Generation, whose integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services.
ComEd, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in northern Illinois, including the City of Chicago.
PECO, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia.
BGE, whose business consists of the purchase and regulated retail sale of electricity and natural gas and the provision of electricity distribution and transmission and natural gas distribution services in central Maryland, including the City of Baltimore.
Pepco, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission in the District of Columbia and major portions of Prince George's County and Montgomery County in Maryland.
DPL, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.
ACE, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in southern New Jersey.
Pepco, DPL and ACE are operating companies of PHI, which is a utility services holding company engaged in the energy transmission and a wholly owned subsidiary of Exelon.distribution businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Exelon has twelvesix reportable segments consisting of Generation’s six reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions in Generation), ComEd, PECO, BGE, and PHI's three utility reportable segments (Pepco,Pepco, DPL, and ACE).ACE. See Note 20 -1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.
PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, engineering, distribution and transmission planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries. These services are directly charged or allocated pursuant to service agreements among PHI Service Company and the participating operating subsidiaries.
Exelon’s consolidated financial information includes the results of its eightseven separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively
referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.
Financial Results of Operations
GAAP Results of Operations
Operations. The following tables settable sets forth Exelon's GAAP consolidated results ofNet income attributable to common shareholders from continuing operations and the Utility Registrants' Net income for the three and nine months ended September 30, 2017March 31, 2023 compared to the same period in 2016. The 2016 amounts include the operations of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2017 | | 2016 | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other | | Exelon | | Exelon(b) | |
Operating revenues | $ | 4,751 |
| | $ | 1,571 |
| | $ | 715 |
| | $ | 738 |
| | $ | 1,310 |
| | $ | (316 | ) | | $ | 8,769 |
| | $ | 9,002 |
| | $ | (233 | ) |
Purchased power and fuel | 2,331 |
| | 529 |
| | 235 |
| | 269 |
| | 473 |
| | (295 | ) | | 3,542 |
| | 3,754 |
| | 212 |
|
Revenue net of purchased power and fuel(a) | 2,420 |
| | 1,042 |
| | 480 |
| | 469 |
| | 837 |
| | (21 | ) | | 5,227 |
| | 5,248 |
| | (21 | ) |
Other operating expenses | | | | | | | | | | | | | | | | | |
Operating and maintenance | 1,374 |
| | 346 |
| | 197 |
| | 175 |
| | 251 |
| | (43 | ) | | 2,300 |
| | 2,338 |
| | 38 |
|
Depreciation and amortization | 410 |
| | 212 |
| | 72 |
| | 109 |
| | 179 |
| | 20 |
| | 1,002 |
| | 1,195 |
| | 193 |
|
Taxes other than income | 141 |
| | 80 |
| | 42 |
| | 61 |
| | 122 |
| | 10 |
| | 456 |
| | 449 |
| | (7 | ) |
Total other operating expenses | 1,925 |
| | 638 |
| | 311 |
| | 345 |
| | 552 |
| | (13 | ) | | 3,758 |
| | 3,982 |
| | 224 |
|
(Loss) Gain on sales of assets | (2 | ) | | — |
| | — |
| | — |
| | — |
| | 1 |
| | (1 | ) | | 1 |
| | (2 | ) |
Bargain purchase gain | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
| | — |
| | 7 |
|
Operating income (loss) | 500 |
| | 404 |
| | 169 |
| | 124 |
| | 285 |
| | (7 | ) | | 1,475 |
| | 1,267 |
| | 208 |
|
Other income and (deductions) | | | | | | | | | | | | | | | | | |
Interest expense, net | (113 | ) | | (89 | ) | | (31 | ) | | (26 | ) | | (62 | ) | | (65 | ) | | (386 | ) | | (516 | ) | | 130 |
|
Other, net | 209 |
| | 5 |
| | 2 |
| | 4 |
| | 13 |
| | 4 |
| | 237 |
| | 120 |
| | 117 |
|
Total other income and (deductions) | 96 |
| | (84 | ) | | (29 | ) | | (22 | ) | | (49 | ) | | (61 | ) | | (149 | ) | | (396 | ) | | 247 |
|
Income (loss) before income taxes | 596 |
| | 320 |
| | 140 |
| | 102 |
| | 236 |
| | (68 | ) | | 1,326 |
| | 871 |
| | 455 |
|
Income taxes | 240 |
| | 131 |
| | 28 |
| | 40 |
| | 83 |
| | (70 | ) | | 452 |
| | 340 |
| | (112 | ) |
Equity in (losses) earnings of unconsolidated affiliates | (8 | ) | | — |
| | — |
| | — |
| | — |
| | 1 |
| | (7 | ) | | (5 | ) | | (2 | ) |
Net income | 348 |
| | 189 |
| | 112 |
| | 62 |
| | 153 |
| | 3 |
| | 867 |
| | 526 |
| | 341 |
|
Net income attributable to noncontrolling interests and preference stock dividends | 43 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 43 |
| | 36 |
| | (7 | ) |
Net income attributable to common shareholders | $ | 305 |
| | $ | 189 |
| | $ | 112 |
| | $ | 62 |
| | $ | 153 |
| | $ | 3 |
| | $ | 824 |
| | $ | 490 |
| | $ | 334 |
|
_________
| |
(a) | The Registrants evaluate operating performance using the measure of revenues net of purchased power and fuel expense. The Registrants believe that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate their operational performance. Revenues net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
| |
(b) | As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from July 1, 2016 through September 30, 2016. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2017 | | 2016 | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other | | Exelon | | Exelon(b) | |
Operating revenues | $ | 13,812 |
| | $ | 4,227 |
| | $ | 2,141 |
| | $ | 2,363 |
| | $ | 3,557 |
| | $ | (951 | ) | | $ | 25,149 |
| | $ | 23,486 |
| | $ | 1,663 |
|
Purchased power and fuel expense | 7,286 |
| | 1,241 |
| | 719 |
| | 853 |
| | 1,318 |
| | (890 | ) | | 10,527 |
| | 9,462 |
| | (1,065 | ) |
Revenue net of purchased power and fuel expense(a) | 6,526 |
|
| 2,986 |
|
| 1,422 |
|
| 1,510 |
|
| 2,239 |
| | (61 | ) |
| 14,622 |
|
| 14,024 |
| | 598 |
|
Other operating expenses | | | | | | | | |
| | | | | | | | |
Operating and maintenance | 4,871 |
| | 1,096 |
| | 595 |
| | 532 |
| | 774 |
| | (136 | ) | | 7,732 |
| | 7,677 |
| | (55 | ) |
Depreciation and amortization | 1,046 |
| | 631 |
| | 213 |
| | 348 |
| | 511 |
| | 65 |
| | 2,814 |
| | 2,821 |
| | 7 |
|
Taxes other than income | 425 |
| | 223 |
| | 116 |
| | 180 |
| | 344 |
| | 25 |
| | 1,313 |
| | 1,168 |
| | (145 | ) |
Total other operating expenses | 6,342 |
|
| 1,950 |
|
| 924 |
|
| 1,060 |
|
| 1,629 |
| | (46 | ) |
| 11,859 |
|
| 11,666 |
| | (193 | ) |
Gain on sales of assets | 3 |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | 4 |
| | 41 |
| | (37 | ) |
Bargain purchase gain | 233 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 233 |
| | — |
| | 233 |
|
Operating income (loss) | 420 |
|
| 1,036 |
|
| 498 |
|
| 450 |
|
| 611 |
| | (15 | ) |
| 3,000 |
|
| 2,399 |
| | 601 |
|
Other income and (deductions) | | | | | | | | | | | | | | | | | |
Interest expense, net | (342 | ) | | (275 | ) | | (93 | ) | | (80 | ) | | (183 | ) | | (221 | ) | | (1,194 | ) | | (1,179 | ) | | (15 | ) |
Other, net | 648 |
| | 14 |
| | 6 |
| | 12 |
| | 40 |
| | 5 |
| | 725 |
| | 377 |
| | 348 |
|
Total other income and (deductions) | 306 |
|
| (261 | ) |
| (87 | ) |
| (68 | ) |
| (143 | ) | | (216 | ) |
| (469 | ) |
| (802 | ) | | 333 |
|
Income (loss) before income taxes | 726 |
| | 775 |
| | 411 |
| | 382 |
| | 468 |
| | (231 | ) | | 2,531 |
| | 1,597 |
| | 934 |
|
Income taxes | 209 |
| | 328 |
| | 84 |
| | 151 |
| | 109 |
| | (286 | ) | | 595 |
| | 625 |
| | 30 |
|
Equity in (losses) earnings of unconsolidated affiliates | (26 | ) | | — |
| | — |
| | — |
| | — |
| | 1 |
| | (25 | ) | | (16 | ) | | (9 | ) |
Net income | 491 |
|
| 447 |
|
| 327 |
|
| 231 |
|
| 359 |
|
| 56 |
|
| 1,911 |
|
| 956 |
| | 955 |
|
Net income attributable to noncontrolling interests and preference stock dividends | 12 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | 26 |
| | 14 |
|
Net income attributable to common shareholders | $ | 479 |
|
| $ | 447 |
|
| $ | 327 |
|
| $ | 231 |
|
| $ | 359 |
| | $ | 56 |
|
| $ | 1,899 |
|
| $ | 930 |
| | $ | 969 |
|
_________
| |
(a) | The Registrants evaluate operating performance using the measure of revenues net of purchased power and fuel expense. The Registrants believe that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate their operational performance. Revenues net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
| |
(b) | As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016. |
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. Exelon’s Net income attributable to common shareholders was $824 million for the three months ended September 30, 2017 as compared to $490 million for the three months ended September 30, 2016, and diluted earnings per average common share were $0.85 for the three months ended September 30, 2017 as compared to $0.53 for the three months ended September 30, 2016.
Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $21 million for the three months ended September 30, 2017 as compared to the same period in 2016. The quarter-over-quarter decrease in Revenue net of purchased power and fuel expense was primarily due to the following unfavorable factors:
Decrease of $36 million at PECO primarily due to unfavorable weathers conditions;
Decrease of $15 million at Generation due to mark-to-market gains of $73 million in 2017 compared to $88 million in 2016; and
Decrease of $11 million at Generation due to the unfavorable impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, increased capacity prices, increased nuclear volumes primarily as a result of the acquisition of FitzPatrick and decreased nuclear outage days, and the addition of two combined-cycle gas turbines in Texas.
The quarter-over-quarter decrease in Revenue net of purchase power and fuel expense was partially offset by the following favorable factors:
Increase of $26 million at PHI primarily due to increased distribution revenue as a result of rate increases; and
Increase of $17 million at BGE primarily due to increased transmission revenue as a result of rate increases.
Operating and maintenance expense decreased by $38 million for the three months ended September 30, 2017 as compared to the same period in 2016 primarily due to the following favorable factors:
Decrease of $32 million at Exelon due to the net recovery of $2 million of merger-related costs in 2017 compared to merger-related costs of $30 million in 2016; and
Decrease of $31 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act.
The quarter-over-quarter decrease in Operating and maintenance expense was partially offset by an increase of $38 million at Generation primarily due to the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016 and higher asset impairment charges, partially offset by decreased nuclear refueling outage costs and labor, contracting and materials expense.
Depreciation and amortization expense decreased by $193 million primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies for the three months ended September 30, 2017 as compared to the same period in 2016.
Taxes other than income increased by $7 millionprimarily due to increased property taxes as a result of the addition of FitzPatrick at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.
Gain on sales of assets remained relatively consistent for the three months ended September 30, 2017 as compared to the same period in 2016.
Bargain purchase gain increased by $7 million due to a measurement period adjustment to the bargain purchase gain for the FitzPatrick acquisition for the three months ended September 30, 2017 as compared to the same period in 2016.
Interest expense, net decreased by $130 million primarily due to additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position, partially offset by the the impact of project in-service dates on the capitalization of interest and higher outstanding debt at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.
Other, net increased by $117 million primarily due to the penalty recorded in the third quarter of 2016 related to Exelon's like-kind exchange tax position and higher net realized gains on NDT funds at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.
Exelon’s effective income tax rates for the three months ended September 30, 2017 and 2016 were 34.1% and 39.0%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for2022. For additional information regarding the components of the effective income tax rates.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Exelon’s Net income attributable to common shareholders was $1,899 million for the nine months ended September 30, 2017 as compared to $930 million for the nine months ended September 30, 2016, and diluted earnings per average common share were $2.01 for the nine months ended September 30, 2017 as compared to $1.00 for the nine months ended September 30, 2016.
Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $598 million for the nine months ended September 30, 2017 as compared to the same period in 2016. The year-over-year increase in Revenue net of purchased power and fuel expense was primarily due to the following favorable factors:
Increase of $96 million at ComEd primarily due to higher electric distribution and transmission formula rate revenues resulting from increased capital investment and higher allowed electric distribution ROE, partially offset by the impact of favorable weather conditions in 2016;
Increase of $83 million at BGE primarily due to the impacts of the electric and natural gas distribution rate increases issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues; and
Increase of $711 million in Revenue net of purchased power and fuel due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, as well as distribution rate increases effective in 2016 and 2017.
The year-over-year increase in Revenue net of purchased power and fuel expense was partially offset by the following unfavorable factors:
Decrease of $180 million at Generation primarily due to the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation's natural gas portfolio, the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, increased nuclear volumes primarily as a result of the acquisition of FitzPatrick, the addition of two combined-cycle gas turbines in Texas and the absence of oil inventory write downs in 2017.
Decrease of $62 million at PECO primarily due to unfavorable weather conditions; and
Decrease of $48 million at Generation due to mark-to-market losses of $161 million in 2017 compared to $113 million in 2016.
Operating and maintenance expense increased by $55 million for the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to the following unfavorable factors:
Increase of $288 million at Generation due to higher asset impairment charges;
Increase of $88 million at Generation due to increased nuclear outage costs;
Increase in Generation's labor, contracting and materials costs of $74 million primarily due to the acquisition of FitzPatrick beginning on March 31, 2017; and
Increase of $253 million at PHI due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.
The year-over-year increase in Operating and maintenance expense was partially offset by the following favorable factors:
Decrease of $589 million at Exelon due to merger commitment and other merger-related costs of $63 million in 2017 compared to $652 million in 2016; and
Decrease of $56 million at BGE primarily due to certain disallowances contained in the June and July 2016 rate orders.
Depreciation and amortization expense decreased by $7 million primarily due to lower accelerated depreciation and amortization expense as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies and the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.
Taxes other than income increased by $145 million primarily due to increased property taxes as a result of the addition of FitzPatrick, increased gross receipts tax expense and increased sales and use tax expense at Generation, as well as the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.
Gain on sales of assets decreased by $37 million primarily due to Generation's gain associated with the sale of the New Boston generating site in 2016.
Bargain purchase gain increased by $233 million due to the gain associated with Generation's acquisition of FitzPatrick in 2017.
Interest expense, net increased by $15 million primarily due to additional interest recorded in the second quarter 2017 related to Exelon's like-kind exchange tax position, higher outstanding debt and the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, partially offset by additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position.
Other, net increased by $348 million primarily due to higher net unrealized and realized gains on NDT funds at Generation for the nine months ended September 30, 2017 as compared to the same period in 2016 and the penalty recorded in 2016 related to Exelon's like-kind exchange tax position.
Exelon’s effective income tax rates for the nine months ended September 30, 2017 and 2016 were 23.5% and 39.1%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
For further detail regarding the financial results for the three and nine months ended September 30, 2017, including explanation of the non-GAAP measure Revenue net of purchased powerMarch 31, 2023 and fuel expense,2022 see the discussions of Results of Operations by Segment below.Registrant.
Adjusted (non-GAAP) Operating Earnings | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, | | Favorable (Unfavorable) Variance |
| | | | | | 2023 | | 2022 | |
Exelon | | | | | | | $ | 669 | | | $ | 481 | | | $ | 188 | |
ComEd | | | | | | | 241 | | | 188 | | | 53 | |
PECO | | | | | | | 166 | | | 206 | | | (40) | |
BGE | | | | | | | 200 | | | 198 | | | 2 | |
PHI | | | | | | | 155 | | | 130 | | | 25 | |
Pepco | | | | | | | 65 | | | 46 | | | 19 | |
DPL | | | | | | | 60 | | | 56 | | | 4 | |
ACE | | | | | | | 33 | | | 26 | | | 7 | |
Other(a) | | | | | | | (93) | | | (241) | | | 148 | |
__________
(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s adjusted (non-GAAP) operating earningscorporate operations, shared service entities, and other financing and investment activities.
The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for the three months ended September 30, 2017March 31, 2022 presented in the table above. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information.
Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $821$28 million or $0.85 per diluted share, compared with adjusted (non-GAAP) operating earnings of $841 million, or $0.91 per diluted shareon a pre-tax basis, for the same period in 2016. Exelon’s adjusted (non-GAAP) operating earnings for the ninethree months ended September 30, 2017March 31, 2022.
Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. Net income attributable to common shareholders from continuing operations increased by $188 million and diluted earnings per average common share from continuing operations increased to $0.67 in 2023 from $0.49 in 2022 primarily due to:
•Higher electric distribution formula rate earnings from higher allowed ROE due to an increase in U.S. treasury rates and impacts of higher rate base at ComEd;
•The favorable impacts of rate increases at PECO, BGE, and PHI;
•Lower BSC costs presented in Exelon’s continuing operations, which were $1,935 million, or $2.05previously allocated to Generation but did not qualify as discontinued operation expenses per diluted share, compared with adjustedthe accounting rules; and
•Carrying costs related to the CMC regulatory assets at ComEd.
The increases were partially offset by:
•Unfavorable weather at PECO and PHI;
•Higher interest expense at BGE and Exelon Corporate;
•An increase in environmental liabilities at Pepco;
•Higher depreciation expense at PECO; and
•Higher credit loss expense at PECO.
Adjusted (non-GAAP) operating earnings of $2,078 million, or $2.24 per diluted share for the same period in 2016. Operating Earnings. In addition to netNet income, Exelon evaluates its operating performance using the measure of adjustedAdjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of period-over-periodyear-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following tables provide a reconciliation between netNet income attributable to common shareholders from continuing operations as determined in accordance with GAAP and adjustedAdjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2017 asMarch 31, 2023 compared to the same period in 2016.2022:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, |
| 2017 | | 2016 |
(All amounts in millions after tax) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
Net Income Attributable to Common Shareholders | $ | 824 |
| | $ | 0.85 |
| | $ | 490 |
| | $ | 0.53 |
|
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $29 and $35, respectively) | (45 | ) | | (0.05 | ) | | (54 | ) | | (0.06 | ) |
Unrealized Gains Related to NDT Fund Investments(b) (net of taxes of $45 and $48, respectively) | (67 | ) | | (0.07 | ) | | (70 | ) | | (0.07 | ) |
Amortization of Commodity Contract Intangibles(c) (net of taxes of $8 and $8, respectively) | 12 |
| | 0.01 |
| | 13 |
| | 0.01 |
|
Merger and Integration Costs(d) (net of taxes of $1 and $10, respectively) | (1 | ) | | — |
| | 13 |
| | 0.01 |
|
Merger Commitments(e) (net of taxes of $1) | — |
| | — |
| | 5 |
| | 0.01 |
|
Long-Lived Asset Impairments(f) (net of taxes of $16 and $5, respectively) | 24 |
| | 0.03 |
| | 11 |
| | 0.01 |
|
Plant Retirements and Divestitures(g) (net of taxes of $47 and $129, respectively) | 71 |
| | 0.08 |
| | 204 |
| | 0.22 |
|
Cost Management Program(h) (net of taxes of $8 and $5, respectively) | 13 |
| | 0.01 |
| | 7 |
| | 0.01 |
|
Like-Kind Exchange Tax Position(i) (net of taxes of $61) | — |
| | — |
| | 199 |
| | 0.21 |
|
Asset Retirement Obligation(j) (net of taxes of $1) | (2 | ) | | — |
| | — |
| | — |
|
Bargain Purchase Gain(k) (net of taxes of $0) | (7 | ) | | (0.01 | ) | | — |
| | — |
|
Reassessment of State Deferred Income Taxes(l) (entire amount represents tax expense) | (21 | ) | | (0.02 | ) | | — |
| | — |
|
Noncontrolling Interests(m) (net of taxes of $4 and $5, respectively) | 20 |
| | 0.02 |
| | 23 |
| | 0.03 |
|
Adjusted (non-GAAP) Operating Earnings | $ | 821 |
| | $ | 0.85 |
| | $ | 841 |
| | $ | 0.91 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, |
| 2023 | | 2022 |
(In millions, except per share data) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
Net Income Attributable to Common Shareholders from Continuing Operations | $ | 669 | | | $ | 0.67 | | | $ | 481 | | | $ | 0.49 | |
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $0) | (1) | | | — | | | — | | | — | |
Change in Environmental Liabilities (net of taxes of $7) | 18 | | | 0.02 | | | — | | | — | |
ERP System Implementation Costs (net of taxes of $0)(a) | — | | | — | | | 1 | | | — | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Change in FERC Audit Liability (net of taxes of $4) | 11 | | | 0.01 | | | — | | | — | |
| | | | | | | |
Separation Costs (net of taxes of $0 and $7, respectively)(b) | (1) | | | — | | | 17 | | | 0.02 | |
Income Tax-Related Adjustments (entire amount represents tax expense)(c) | — | | | — | | | 134 | | | 0.14 | |
Adjusted (non-GAAP) Operating Earnings | $ | 696 | | | $ | 0.70 | | | $ | 634 | | | $ | 0.64 | |
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
(All amounts in millions after tax) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
Net Income Attributable to Common Shareholders | $ | 1,899 |
| | $ | 2.01 |
| | $ | 930 |
| | $ | 1.00 |
|
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $62 and $46, respectively) | 97 |
| | 0.10 |
| | 67 |
| | 0.07 |
|
Unrealized Gains Related to NDT Fund Investments(b) (net of taxes of $137 and $89, respectively) | (211 | ) | | (0.22 | ) | | (127 | ) | | (0.13 | ) |
Amortization of Commodity Contract Intangibles(c) (net of taxes of $17 and $6, respectively) | 27 |
| | 0.03 |
| | 8 |
| | 0.01 |
|
Merger and Integration Costs(d) (net of taxes of $24 and $36, respectively) | 39 |
| | 0.04 |
| | 92 |
| | 0.10 |
|
Merger Commitments(e) (net of taxes of $137 and $114, respectively) | (137 | ) | | (0.15 | ) | | 400 |
| | 0.43 |
|
Long-Lived Asset Impairments(f) (net of taxes of $188 and $67, respectively) | 293 |
| | 0.31 |
| | 104 |
| | 0.11 |
|
Plant Retirements and Divestitures(g) (net of taxes of $89 and $214, respectively) | 137 |
| | 0.15 |
| | 338 |
| | 0.37 |
|
Cost Management Program(h) (net of taxes of $15 and $17, respectively) | 24 |
| | 0.03 |
| | 26 |
| | 0.03 |
|
Like-Kind Exchange Tax Position(i) (net of taxes of $66 and $61, respectively) | (26 | ) | | (0.03 | ) | | 199 |
| | 0.21 |
|
Asset Retirement Obligation(j) (net of taxes of $1) | (2 | ) | | — |
| | — |
| | — |
|
Bargain Purchase Gain(k) (net of taxes of $0) | (233 | ) | | (0.25 | ) | | — |
| | — |
|
Reassessment of State Deferred Income Taxes(l) (entire amount represents tax expense) | (42 | ) | | (0.04 | ) | | — |
| | — |
|
Tax Settlements(n) (net of taxes of $1) | (5 | ) | | (0.01 | ) | | — |
| | — |
|
Noncontrolling Interests(m) (net of taxes of $16 and $8, respectively) | 75 |
| | 0.08 |
| | 41 |
| | 0.04 |
|
Adjusted (non-GAAP) Operating Earnings | $ | 1,935 |
| | $ | 2.05 |
| | $ | 2,078 |
| | $ | 2.24 |
|
___________________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, theThe marginal statutory income tax rates for 2023 and 2022 ranged from 39.0 percent24.0% to 41.0 percent. Under IRS regulations, NDT fund investment returns are taxed at differing rates for investments in qualified vs. non-qualified funds. The tax rates applied to unrealized gains and losses29.0%.
(a)Reflects costs related to NDT Fund investments were 43.2 percenta multi-year ERP system implementation, which are recorded in Operating and 46.2 percentmaintenance expense.
(b)Represents costs related to the separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs, which are recorded in Operating and maintenance expense.
(c)In connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs.
Significant 2023 Transactions and Developments
Separation
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the threepurpose of separation and nine months ended September 30, 2017, respectively,holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and 52.6 percent and 52.5 percentfinancial results. Accordingly, the separation met the criteria for the three and nine months ended September 30, 2016, respectively.
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(a) | Reflects the impact of net gains and losses on Generation’s economic hedging activities. See Note 10 - Derivative Financial Instrumentsdiscontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s hedging activities. |
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(b) | Reflects the impact of net unrealized gains on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 13 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments. |
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(c) | Reflects the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions in 2017, and in 2016, the Integrys and ConEdison Solutions acquisitions. |
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(d) | Reflects certain costs incurred for the PHI acquisition in 2017 and 2016 and Generation's FitzPatrick acquisition in 2017, including professional fees, employee-related expenses and integration activities. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to merger and acquisition costs. |
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(e) | Represents a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions in 2017, and costs and adjustments incurred as part of the settlement orders approving the PHI acquisition in 2017 and 2016. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to PHI Merger commitments. |
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(f) | Primarily reflects impairments as a result of the ExGenTexas Power, LLC assets held for sale in 2017 and impairments of Upstream assets and certain wind projects at Generation in 2016. |
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(g) | Primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, partially offset in 2016 by a gain associated with Generation's sale of the New Boston generating site and Generation's decision to early retire the Three Mile Island nuclear facility in 2017. |
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(h) | Reflects severance and reorganization costs related to a cost management program. |
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(i) | Represents adjustments to income tax, penalties and interest expenses in 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position, and in 2016, the recognition of a penalty and associated interest expense in 2016 as a result of a tax court decision on Exelon’s like-kind exchange tax position. |
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(j) | Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the nonregulatory units. |
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(k) | Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition. |
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(l) | Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. |
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(m) | Represents elimination from Generation’s results of the noncontrolling interest related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG. |
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(n) | Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation. |
Merger, Integration and Acquisition Costs
As a result of the PHI Merger that was completed on March 23, 2016, the Registrants have incurred costs associated with evaluating, structuring and executing the PHI Merger transaction itself, and will continue to incur cost associated with meeting the various commitments set forth by regulators and agreed-upon with other interested parties as part of the merger approval process, and integrating the former PHI businesses into Exelon. In addition, as a result of the acquisition of the FitzPatrick nuclear generating station on March 31, 2017, Exelon and Generation incurred costs associated with evaluating, structuring, and executing the transaction and integrating FitzPatrick into Exelon.
For the three and nine months ended September 30, 2017 and 2016, expense has been recognized for the PHI Merger and Generation's FitzPatrick acquisition as follows:
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pre-tax Expense |
| | Three Months Ended September 30, 2017 |
Merger, Integration and Acquisition Costs: | | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI(a)(b) | | Pepco(a)(c) | | DPL(a) | | ACE(a)(d) |
Transaction(e) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Other(f) | | (3 | ) | | 11 |
| | — |
| | 1 |
| | 1 |
| | (15 | ) | | (8 | ) | | 1 |
| | (8 | ) |
Total | | $ | (3 | ) | | $ | 11 |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | (15 | ) | | $ | (8 | ) | | $ | 1 |
| | $ | (8 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pre-tax Expense |
| | Three Months Ended September 30, 2016 |
Merger, Integration and Acquisition Costs: | | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI(a) | | Pepco(a) | | DPL(a) | | ACE(a) |
Transaction(e) | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Employee-Related(g) | | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
|
Other(f) | | 21 |
| | 11 |
| | — |
| | 2 |
| | 2 |
| | 7 |
| | 3 |
| | 2 |
| | 2 |
|
Total | | $ | 23 |
| | $ | 11 |
| | $ | — |
| | $ | 2 |
| | $ | 2 |
| | $ | 8 |
| | $ | 3 |
| | $ | 2 |
| | $ | 2 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pre-tax Expense |
| | Nine Months Ended September 30, 2017 |
Merger, Integration and Acquisition Costs: | | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI(a)(b) | | Pepco(a)(c) | | DPL(a)(h) | | ACE(a)(d) |
Transaction(e) | | $ | 5 |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Other(f) | | 57 |
| | 67 |
| | 1 |
| | 3 |
| | 3 |
| | (17 | ) | | (6 | ) | | (6 | ) | | (6 | ) |
Total | | $ | 62 |
| | $ | 71 |
| | $ | 1 |
| | $ | 3 |
| | $ | 3 |
| | $ | (17 | ) | | $ | (6 | ) | | $ | (6 | ) | | $ | (6 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pre-tax Expense |
| | Nine Months Ended September 30, 2016 |
Merger, Integration and Acquisition Costs: | | Exelon(a) | | Generation(a) | | ComEd(i) | | PECO | | BGE(j) | | PHI(a)(b) | | Pepco(a)(c) | | DPL(a)(h) | | ACE(a) |
Transaction(e) | | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Employee-Related(g) | | 74 |
| | 10 |
| | 1 |
| | 1 |
| | 1 |
| | 61 |
| | 29 |
| | 17 |
| | 14 |
|
Other(f) | | 16 |
| | 21 |
| | (8 | ) | | 3 |
| | (3 | ) | | 2 |
| | (3 | ) | | 1 |
| | 3 |
|
Total | | $ | 126 |
| | $ | 31 |
|
| $ | (7 | ) |
| $ | 4 |
|
| $ | (2 | ) | | $ | 63 |
| | $ | 26 |
| | $ | 18 |
| | $ | 17 |
|
_________
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(a) | For Exelon, Generation, PHI, Pepco, DPL, and ACE, includes the operations of the acquired businesses beginning on March 24, 2016. |
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(b) | For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $16 million and $24 million, respectively, incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. For the Successor period March 24, 2016 to September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $13 million incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information. |
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(c) | For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $10 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information. |
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(d) | For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ACE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information. |
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(e) | External, third party costs paid to advisors, consultants, lawyers and other experts to integrate PHI processes and systems into Exelon, to assist in the due diligence and regulatory approval processes and in the closing of transactions. |
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(f) | Costs to integrate PHI processes and systems into Exelon. For the three and nine months ended September 30, 2017, also includes costs to integrate FitzPatrick processes and systems into Exelon. |
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(g) | Costs primarily for employee severance, pension and OPEB expense and retention bonuses. |
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(h) | For the nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $3 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information. |
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(i) | For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, incurred at ComEd that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information. |
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(j) | For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million incurred at BGE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information. |
As of September 30, 2017, Exelon expects to incur total PHI acquisition and integration related costs of approximately $700 million, excluding merger commitments. Of this amount, including costs incurred from 2014 through September 30, 2017, Exelon and PHI have incurred approximately $675 million.
Significant 2017 Transactions and Developments
Early Retirement of Three Mile Island Facility
On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year and will not receive capacity revenue for that period, the third consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently committed to operate through May 2019. In 2017, as a result of the plant retirement decision of TMI, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $76 million related to materials and supplies inventory reserve adjustments, employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of TMI primarily related to accelerated depreciation of plant assets (including any asset retirement costs (ARC)), accelerated amortization of nuclear fuel, and additional asset retirement obligation (ARO) accretion expense associated with the changes in decommissioning timing and cost assumptions. During the three and nine months ended September 30, 2017, both Exelon’s and Generation’s results include an incremental $112 million and $149 million, respectively, of pre-tax expense for these items.
The following table summarizes the estimated annual amount and timing of expected incremental non-cash expense items through 2019.
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| | | | | | | | | | | | | | | | |
| | September 30, 2017 | | Projected(a) |
Income statement expense (pre-tax) | | | 2017 | | 2018 | | 2019 |
Depreciation and Amortization | | | | | | | | |
Accelerated depreciation(b) | | $ | 141 |
| | $ | 250 |
| | $ | 430 |
| | $ | 325 |
|
Accelerated nuclear fuel amortization | | 8 |
| | 10 |
| | 20 |
| | 5 |
|
Total | | $ | 149 |
| | $ | 260 |
| | $ | 450 |
| | $ | 330 |
|
_________
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(a) | Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc. |
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(b) | Reflects incremental accelerated depreciation of plant assets, including any ARC. |
EGTP Consent Agreement
In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. EGTP’s operating cash flows have been negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. As a result, in the second quarter 2017, Exelon and Generation classified certain EGTP assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheets. For the three and nine months ended September 30, 2017, a $40 million and $458 million pre-tax impairment loss was recorded within Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4 - Mergers, Acquisitions and Dispositions, Note 6 - Impairment of Long-Lived Assets and Note 11 - Debt and Credit Agreements for more information for additional information regarding EGTP and the associated nonrecourse debt.
Acquisition of James A. FitzPatrick Nuclear Generating Station
On March 31, 2017, Generation acquired the 838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station for a total purchase price of $289 million. In accounting for the acquisition as a business combination, Exelon and Generation recorded an after-tax bargain purchase gain of $233 million which is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information regardingon the Generation's acquisition of FitzPatrickseparation and related costs.discontinued operations.
Illinois Future Energy Jobs Act
On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA was effective June 1, 2017, and includes, among other provisions, (1) a Zero Emission Standard (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 and (7) support for low income rooftop and community solar programs. FEJA establishes new or adjusts existing rate recovery mechanisms for ComEd to recover costs associatedIn connection with the new or expanded energy efficiencyseparation, Exelon incurred separation (benefit)/costs impacting continuing operations of $(1) million and RPS requirements. Regulatory or legal challenges over$24 million on a pre-tax basis for the validitythree months ended March 31, 2023 and 2022, respectively, which are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of FEJA2023 are possible. See Note 5 - Regulatory Mattersnot expected to be material. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA. See Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information regarding the economic challenges facing Generation's Clintonseparation, and Quad Cities nuclear plants and the expected benefits of the ZES.
employee-related severance costs.
Dismissal of Litigation Challenging ZEC Programs
On July 14, 2017, the U.S. District Court for the Northern District of Illinois dismissed two lawsuits challenging the ZEC program contained in FEJA. On July 17, 2017, the plaintiffs appealed the court’s decisions to the U.S. Court of Appeals for the Seventh Circuit. Plaintiffs-Appellants initial brief was filed on August 28, 2017 and the state’s and Exelon’s briefs were filed on October 27, 2017. Reply briefs are due on December 12, 2017.
Additionally, on July 25, 2017, the U.S. District Court for the Southern District of New York dismissed a lawsuit challenging the ZEC program contained in the New York CES. On August 24, 2017, the plaintiffs appealed the decision to the Second Circuit. Plaintiffs-Appellants’ initial brief was filed on October 13 and the state’s and Exelon’s briefs are due on November 17, 2017. Reply briefs are due on December 1, 2017.
These court decisions uphold the ZEC programs which support Illinois’s and New York’s efforts to advance clean energy and preserve affordable and reliable energy resources for customers. See Note 5 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA and the New York CES.
Merger Commitment Unrecognized Tax Benefits
Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in 2016. In the first quarter 2017, as a part of its examination of Exelon’s return, the IRS National Office issued guidance concurring with Exelon’s position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively, as of September 30, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.
Combined-Cycle Gas Turbine Projects
In June 2017, Generation commenced commercial operations of two new combined-cycle gas turbines (CCGTs) at the Colorado Bend and Wolf Hollow Generating Stations in Texas. The two new CCGTs have added nearly 2,200 MWs of capacity to Generation’s fleet, enhancing Generation’s strategy to match generation to customer load. Generation invested approximately $1.5 billion over the past three years to complete the new plant construction, which utilizes new General Electric technology to make them among the cleanest, most efficient CCGTs in the nation.
Utility Rates andDistribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.
statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2017.
Completed Distribution Rate Case Proceedings
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| | | | | | | | | | | | | |
Company | | Jurisdiction | | Approved Revenue Requirement Increase (in millions) | | Approved Return on Equity | | Completion Date | | Rate Effective Date |
DPL | | Maryland (Electric) | | $ | 38 |
| | 9.6 | % | | February 15, 2017 | | February 15, 2017 |
DPL | | Delaware (Electric) | | $ | 31.5 |
| | 9.7 | % | | May 23, 2017 | | June 1, 2017 |
DPL | | Delaware (Natural Gas) | | $ | 4.9 |
| | 9.7 | % | | June 6, 2017 | | July 1, 2017 |
Pepco | | District of Columbia (Electric) | | $ | 37 |
| | 9.5 | % | | July 25, 2017 | | August 15, 2017 |
ACE | | New Jersey (Electric) | | $ | 43 |
| | 9.6 | % | | September 22, 2017 | | October 1, 2017 |
Pepco | | Maryland (Electric) | | $ | 32 |
| | 9.5 | % | | October 27, 2017 | | October 20, 2017 |
Pending Distribution Rate Case Proceedings
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| | | | | | | | | | | | | |
Company | | Jurisdiction | | Requested Revenue Requirement Increase (in millions) | | Requested Return on Equity | | Filing Date | | Expected Completion Timing |
ComEd | | Illinois (Electric)(a) | | $ | 96 |
| (b) | 8.4 | % | (c) | April 13, 2017 | | Fourth quarter 2017 |
DPL | | Maryland (Electric) | | $ | 22 |
| | 10.1 | % | | July 14, 2017 (Updated on September 28, 2017) | | First quarter 2018 |
DPL | | Delaware (Electric) | | $ | 31 |
| | 10.1 | % | | August 17, 2017 (Updated on October 18, 2017) | | Third quarter 2018 |
DPL | | Delaware (Natural Gas) | | $ | 13 |
| | 10.1 | % | | August 17, 2017 | | Third quarter 2018 |
________
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(a) | Pursuant to EIMA, ComEd’s electric distribution rates are established through a performance-based formula through which ComEd is required to file an annual update on or before May 1, 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 for the year (annual reconciliation). |
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(b) | Reflects an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation. |
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(c) | ComEd’s allowed ROE under its electric distribution formula rate is the annual average rate on 30-year treasury notes plus 580 basis points and is subject to reduction if ComEd does not deliver certain reliability and customer service benefits. The initial revenue requirement for 2017 reflects an allowed ROE of 8.40%, while the annual reconciliation reflects an allowed ROE of 8.34%, which is inclusive of a 6 basis point performance penalty. |
Transmission Formula Rates
The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's 2017 annual electric transmission formula rate filings:
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| | | | | | | | | | | | | | | | | | | |
| 2017 |
Annual Transmission Filings(a) | ComEd | | BGE | | Pepco | | DPL | | ACE |
Initial revenue requirement increase | $ | 44 |
| | $ | 31 |
| | $ | 5 |
| | $ | 6 |
| | $ | 20 |
|
Annual reconciliation (decrease) increase | (33 | ) | | 3 |
| | 15 |
| | 8 |
| | 22 |
|
Dedicated facilities decrease(b) | — |
| | (8 | ) | | — |
| | — |
| | — |
|
Total revenue requirement increase | $ | 11 |
| | $ | 26 |
| | $ | 20 |
| | $ | 14 |
| | $ | 42 |
|
| | | | | | | | | |
Allowed return on rate base(c) | 8.43 | % | | 7.47 | % | | 7.92 | % | | 7.16 | % | | 8.02 | % |
Allowed ROE(d) | 11.50 | % | | 10.50 | % | | 10.50 | % | | 10.50 | % | | 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. |
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(c) | Represents the weighted average debt and equity return on transmission rate bases. |
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(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, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization. |
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate 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. 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. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.
2023. See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details on these regulatory proceedings.
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. In the petitions and supporting documents, Westinghouse makes clear that its requests for relief center on one business area that is losing money3 — the construction of nuclear power plants in Georgia and South Carolina. Through the bankruptcy, Westinghouse seeks to reorganize around its profitable core business, which includes nuclear fuel fabrication and related services and other services provided to existing nuclear power plants in the U.S. and around the world. For these reasons, at this time, Generation does not anticipate disruption to the Westinghouse fuel fabrication contracts for Braidwood, Byron, or Ginna or other existing contracts for Generation's nuclear power plants. Generation is monitoring the bankruptcy proceeding to ensure that its rights are protected.
ExGen Renewables Holdings, LLC Transaction
On July 6, 2017, ExGen Renewables Holdings, LLC, a wholly owned subsidiary of Generation, completed the sale of a 49% interest of ExGen Renewables Partners, LLC, a newly formed owner and operator of approximately 1,296 megawatts of Generation's operating wind and solar electric generating facilities. ExGen Renewables Holdings will be the managing member of ExGen Renewables Partners, LLC, and have day-to-day control and management
over its renewable generation portfolio. The closing of the transaction was subject to certain regulatory approvals, including the Federal Energy Regulatory Commission (FERC) and the Public Utility Commission of Texas (PUCT) which were received during the second quarter of 2017. The sale price was $400 million plus immaterial working capital and other customary post-closing adjustments. The net proceeds, after approximately $100 million of income taxes, will be used to pay down debt and for general corporate purposes. Generation will continue to consolidate ExGen Renewables Partners, LLC and will record a noncontrolling interest on its Consolidated Balance Sheet for the investor's initial equity share as well as earnings attributable to the noncontrolling interest in the Consolidated Statements of Operations and Comprehensive Income each period going forward.
Hurricanes Harvey, Irma and Maria Impacts
Although Exelon subsidiaries provided substantial assistance to recovery efforts following Hurricanes Harvey and Irma, Hurricanes Harvey, Irma and Maria are not expected to have a material impact on the Registrants’ businesses or financial results given the limited operations in the areas affected by the storms.
Exelon’s Strategy and Outlook for 2017 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:
Exelon’s utilities provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Exelon utilities only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon's Board of Directors has approved a dividend policy providing a raise of 2.5% each year for three years, beginning with the June 2016 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions
to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS of the Exelon 2016 Form 10-K for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In a cost management program initiated late in 2015, the company committed to reducing operation and maintenance expenses and capital costs by approximately $350 million and $50 million, respectively, of which approximately 35% of run-rate savings was achieved by the end of 2016. Approximately 60% of run-rate savings are expected to be achieved by the end of 2017 and fully realized in 2018. At least 75% of the savings are expected to be related to Generation, with the remaining amount related to the Utility Registrants.
In November 2017, Exelon announced the elimination of approximately $250 million of annual ongoing costs, primarily at Generation, by 2020. This announcement is a result of Exelon’s continuous focus on improving its cost profile through enhanced efficiency and productivity. These cost reductions result in a cost profile that better aligns with current market conditions. The targeted cost savings are incremental to the expected savings from previous cost management initiatives.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The PHI merger provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $25 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $9 billion by the end of 2021. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.information.
Competitive Energy Businesses.Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of September 30, 2017, Generation has currently approved plans to invest a total of approximately $300 million through 2018 to complete new plant construction currently in progress.Completed Distribution Base Rate Case Proceedings
Liquidity Considerations
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources - Credit Matters - Exelon Credit Facilities below.
For further detail regarding the Registrants' liquidity for the nine months ended September 30, 2017, see Liquidity and Capital Resources discussion below.
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Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
ComEd - Illinois | | April 15, 2022 | | Electric | | $ | 199 | | | $ | 199 | | | 7.85 | % | | November 17, 2022 | | January 1, 2023 |
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PECO - Pennsylvania | | March 31, 2022 | | Natural Gas | | 82 | | | 55 | | | N/A | | October 27, 2022 | | January 1, 2023 |
BGE - Maryland | | May 15, 2020 (amended September 11, 2020) | | Electric | | 203 | | | 140 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 |
| | Natural Gas | | 108 | | | 74 | | | 9.65 | % | | |
Pepco - Maryland | | October 26, 2020 (amended March 31, 2021) | | Electric | | 104 | | | 52 | | | 9.55 | % | | June 28, 2021 | | June 28, 2021 |
DPL - Maryland | | May 19, 2022 | | Electric | | 38 | | | 29 | | | 9.60 | % | | December 14, 2022 | | January 1, 2023 |
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Pending Distribution Base Rate Case Proceedings
Project Financing | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing |
ComEd - Illinois | | January 17, 2023 | | Electric | | $ | 1,472 | | | 10.50% to 10.65% | | Fourth quarter of 2023 |
ComEd - Illinois | | April 21, 2023 | | Electric | | 247 | | | 8.91 | % | | Fourth quarter of 2023 |
BGE - Maryland | | February 17, 2023 | | Electric | | 313 | | | 10.40 | % | | Fourth quarter of 2023 |
Natural Gas | 289 | | | 10.40 | % | |
Pepco - District of Columbia | | April 13, 2023 | | Electric | | 191 | | | 10.50 | % | | First quarter of 2024 |
DPL - Delaware | | December 15, 2022 (amended February 28, 2023) | | Electric | | 48 | | | 10.50 | % | | Second quarter of 2024 |
ACE - New Jersey | | February 15, 2023 | | Electric | | 105 | | | 10.50 | % | | First quarter of 2024 |
Generation utilizes individual project financings as a means to financeTransmission Formula Rates
For 2023, the construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure,following increases/(decreases) were included in which project debt and equity used to finance the project are paid back from the cash generated by the newly constructed asset once operational. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.BGE's annual electric transmission formula rate updates. See Note 6 Impairment of Long-Lived Assets and Note 11 - Debt and Credit Agreements3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
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Registrant | | Initial Revenue Requirement Increase | | Annual Reconciliation Decrease | | Total Revenue Requirement Increase | | Allowed Return on Rate Base | | Allowed ROE |
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BGE | | $ | 19 | | | $ | (12) | | | $ | 4 | | | 7.34 | % | | 10.50 | % |
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ComEd's FERC Audit
The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in May 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 through August 31, 2022. On January 17 and February 21, 2023, ComEd was provided with information on nonrecourse debt.a series of potential findings, including concerning ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. As of March 31, 2023, ComEd has continued discussions with FERC staff and determined that a loss is probable and has recorded a liability that reflects management's best estimate. The final outcome and resolution of the findings or of the audit itself cannot be predicted and the results, while not reasonably estimable at this time, could be material to the Exelon and ComEd financial statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other Key Business Drivers and Management Strategies
Power Markets
PriceThe following discussion of Fuels
The useother key business drivers and management strategies includes current developments of previously disclosed matters and new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which resultsissues arising during the period that may impact future financial statements. This section should be read in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
Capacity Market Changes in PJM
In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliability largely by limiting the excuses for non-performance and by increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to improve reliability, to reduce energy production costs as a result of more efficient operations and to reduce the need for out of market energy payments to suppliers. Generation participated actively in PJM’s stakeholder process through which PJM developed the proposal and also actively participatedconjunction with ITEM 1. Business in the FERC proceeding including filing comments. On June 9, 2015, FERC approved PJM's filing largely as proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. As a result2022 Form 10-K, ITEM 7. Management's Discussion and Analysis of thisFinancial Condition and several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015)Results of Operations — Other Key Business Drivers and its transitional auction for delivery year 2016/2017 (results posted on August 31, 2015) and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015). On May 10, 2016, FERC largely denied rehearing, and a number of parties appealed to the U.S. Court of Appeals for the DC Circuit for review of the decision. On June 20, 2017, the DC Circuit denied all the appeals.
MISO Capacity Market Results
On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of its capacity auction covering the June 2015 through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation had an offer that was selectedManagement Strategies in the auction. However, due to Generation's ratable hedging strategy, the results of the capacity auction have not had a material impact on Exelon's and Generation's consolidated results of operations and cash flows.
Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest Electric Cooperative, Public Citizens, Inc., and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the 2015/2016 delivery in MISO delivery zone 4. The complaints allege generally that 1) the results of the capacity auction for zone 4 are not just and reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be established and that 4) certain alleged behavior by one of the market participants other than Exelon or Generation, be investigated.
On October 1, 2015, FERC announced that it was conducting a non-public investigation (that does not involve Exelon or Generation) into whether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, FERC issued a decision that certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. FERC ordered that certain rules be changed prior to the April 2016 auction which set capacity prices for the 2016/2017 planning year. In response to this order, MISO filed certain rule changes with FERC. On March 18, 2016, FERC largely denied rehearing of its December 31, 2015 order. FERC continues to conduct its non-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds are appropriate. FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings. Generation cannot predict the impact the FERC order may ultimately have on future auction results, capacity pricing or decisions related to the potential early retirement of the Clinton nuclear plant, however, such impacts could be material to Generation's future results of operations and cash flows. See Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on the impacts of the MISO announcement.
Subsidized Generation
The rate of expansion of subsidized generation, in the markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s results of operations.
Various states have attempted to implement or propose legislation, regulations or other policies to subsidize new generation development which may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted into law in January 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected three proposals to participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV was required to construct an approximately 700 MW combined cycle gas turbine in Waldorf, Maryland. The CfD mandated that utilities (including BGE, Pepco and DPL) pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market.
Exelon and others challenged the constitutionality and other aspects of the New Jersey legislation in federal court. The actions taken by the MDPSC were also challenged in federal court in an action to which Exelon was not a party. The federal trial courts in both the New Jersey and Maryland actions effectively invalidated the actions taken by the New Jersey legislature and the MDPSC, respectively. Each of those decisions was upheld by the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth Circuit, respectively. On April 19, 2016, the U.S. Supreme Court affirmed the decision of the U.S. Court of Appeals for the Fourth Circuit, and subsequently denied certiorari with respect to the appeal from the U.S. Court of Appeals for the Third Circuit, leaving in place that Court’s decision. The matter is now considered closed.
As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered and cleared in PJM’s capacity market auctions. To the extent that the state-required customer subsidies are included under their respective contracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon. While the court decisions are positive developments, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon’s position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows.
One such state is Ohio, where state-regulated utility companies FirstEnergy Ohio (FE) and AEP Ohio (AEP) initiated actions at the Public Utilities Commission of Ohio (PUCO) to obtain approval for Riders that would effectively allow these two companies to pass through to all customers in their service territories the differences between their costs and market revenues on PPAs entered into between the utility and its merchant generation affiliate for what was collectively more than 6,000 MW of primarily coal-fired generation. Thus, the Riders were similar to the CfDs described above (except that the PPA Riders in Ohio would apply to existing generation facilities whereas the CfDs applied to new generation facilities). While FERC orders on April 27, 2016 largely alleviated the concerns related to the Riders by holding that the PPAs ran afoul of affiliate restrictions on FE and AEP, we continue to closely monitor developments in Ohio.
In addition, Exelon continues to monitor developments in Maryland, New Jersey, and other states and participates in stakeholder and other processes to ensure that similar state subsidies are not developed. Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/ or consumers to subsidize 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.
Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs
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. The EPSA parties have filed motion to expedite both proceedings. 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 in NYISO and PJM 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. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.
DOE Notice of Proposed Rulemaking
On August 23, 2017, the DOE released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September, 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On October 2, 2017, the FERC issued a notice inviting comments regarding the DOE NOPR within 21 days and established a new docket wherein the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPR and urging the agency to take swift action to protect customers from power supply interruptions
and ensure resiliency in a way that appropriately balances the value and cost to customers. Exelon cannot predict the final outcome of the proceeding or its potential impact, if any, on Exelon or Generation.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in flat to declining load growth in electricity for the utilities. There is a decrease in projected load for electricity for ComEd, PECO, BGE, and ACE, and an essentially flat projected load for electricity for DPL. ComEd, PECO, BGE, Pepco, DPL, and ACE are projecting load volumes to decrease by (1.2)%, (0.4)%, (2.9)%, (2.3)%, (0.4)%, and (3.5)% respectively, in 2017 compared to 2016.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. The market experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and consolidations within the industry during the year. However, forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Strategic Policy Alignment
As part of its strategic business planning process, Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.
Exelon's board of directors declared first quarter 2017 dividends of $0.3275 per share on Exelon's common stock. The first quarter 2017 dividend was paid on March 10, 2017. The dividend increased from fourth quarter 2016 amount to reflect the Board's decision to raise Exelon's dividend 2.5% each year for the next three years, beginning with the June 2016 dividend.
Exelon's Board of Directors declared the second quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The second quarter 2017 dividend was paid on June 9, 2017.
Exelon's Board of Directors declared the third quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The third quarter 2017 dividend was paid on September 8, 2017.
Exelon's Board of Directors declared the fourth quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The fourth quarter 2017 dividend is payable on December 8, 2017.
All future quarterly dividends require approval by Exelon's Board of Directors.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2017 and 2018. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of September 30, 2017, the percentage of expected generation hedged is 98%-101%, 79%-82% and 45%-48% for 2017, 2018, and 2019 respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and
swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 60% of Generation’s uranium concentrate requirements from 2017 through 2021 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Tax Matters
Potential Corporate Tax Reform
President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform. On September 27, 2017, the Trump Administration and Republican Congressional leaders issued a unified framework which outlines their goals for comprehensive tax reform. Specifically, the framework proposes a reduction in the corporate tax rate from the current 35% to 20%, immediate expensing of new investments in depreciable assets for at least five years, elimination of the domestic production activities deduction and partial limitation of the deduction for interest. It is uncertain whether, to what extent, or when any changes in federal tax policies will be enacted or the transition time frame for such changes. The Utility Registrants’ regulators may impose rate reductions to provide the benefit of any reduction in income tax expense to customers as well as to refund the "excess" deferred income taxes previously collected through rates. The amount and timing of any such rate changes would be subject to the discretion of the rate regulator in each specific jurisdiction. For these reasons, the Registrants cannot predict the impact any potential changes may have on their future results of operations, cash flows or financial position, and such changes could be material.
Environmental Legislative and Regulatory Developments
Exelon was actively involved in the Obama Administration’s development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants.
Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are
the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Mercury and Air Toxics Standard Rule (MATS). On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two year extension in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. The EPA has also indicated its intent to issue an advance notice of proposed rulemaking to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.
2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meet the October 1, 2017 deadline to promulgate initial designations for areas in attainment or non-attainment of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to compel EPA to issue the designations.
Water Quality
Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. Those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom, Quad Cities, Riverside and Salem. See ITEM 1.—BUSINESS, "Water Quality" of the Exelon 20162022 Form 10-K, for further discussion.
Solid and Hazardous Waste
In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classifies CCR as non-hazardous waste under RCRA. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the new federal regulations for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations.
See Note 18—12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for further detail related toadditional information on various environmental matters, including the impact of environmental regulation.matters.
Other Legislative and Regulatory Developments
NRC Task ForceCity of Chicago Franchise Agreement
The current ComEd Franchise Agreement with the City of Chicago (the City) has been in force since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on Fukushima Daiichi Accident (Exelonone year notice as of December 31, 2020. It now continues in effect indefinitely unless and Generation).
In July 2011,until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an NRC Task Force formed inoption to terminate and purchase the aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station,ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a reportnotice of termination at this time, the City has not exercised its review ofmunicipalization option, and no new agreement has become effective. Accordingly, the accident, including tiered recommendations1992 Franchise Agreement remains in effect at this time. In April 2021, the City invited interested parties to respond to a Request for future regulatory actionInformation (RFI) regarding the franchise for electricity delivery. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. ComEd submitted its response to the RFI by the NRCdue date. However, the City did not proceed to be taken inissue an RFP. Since that time, ComEd and the nearCity continued to negotiate and longer term.have arrived at a proposed Chicago Franchise Agreement (CFA) and an Energy and Equity Agreement (EEA). These agreements together are intended to grant ComEd the right to continue providing electric utility services using public ways within the City of Chicago, and to create a new non-profit entity to advance energy and energy-related equity projects. On February 1, 2023, the proposed CFA and EEA were introduced to the City Council. The Task Force’s report concluded that nuclear reactors in the United States are operating safelyproposed CFA and do not present an imminent riskEEA remain subject to public health and safety. The NRC and its staff have issued orders and implementation guidance for commercial reactor licensees operating in the United States. Generation has assessed the impacts of the Tier 1 orders and information requests and will continue monitoring the additional recommendations under reviewapproval by the NRC staff, both from an operationalCity Council and a financial impact standpoint. Generation’s current assessments are specific to the Tier 1 recommendations. In May 2017, the NRC finalized its decision that no actions are required with respect to the Tier 2Exelon Board.
While Exelon and Tier 3 recommendations. Generation will continue to engage in nuclear industry assessments and actions and obtain stakeholder input.
Employees
In January 2017, an election was held at BGE which resulted in union representation for approximately 1,400 employees. BGE and IBEW Local 410 have begun negotiations for an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and managementComEd cannot predict the ultimate outcome of such negotiations.these processes, fundamental changes in the agreements or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with FERC.
Infrastructure Investment and Jobs Act
On November 15, 2021, President Biden signed the $1.2 trillion IIJA into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. Federal agencies are developing guidelines to implement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. The Registrants are continuing to analyze the legislation and considering possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.
In September 2022, ComEd and BGE applied for the MMG, which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. The grant process is expected to be highly competitive, and therefore, ComEd and
BGE cannot predict how many of their total applications will be approved as filed or the precise timing of receiving any funds if they are awarded a grant.
In March 2023, Exelon, ComEd and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of distributed energy resources (DERs) and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In April 2017,2023, ComEd, PECO BGE and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. Through its applications under section 40107 and 40101(c) of IIJA, the Registrants are requesting nearly $700 million in proposed federal funding. The grant process is expected to be highly competitive, and therefore, the Registrants cannot predict how many of their total applications will be approved as filed, or the precise timing of receiving any funds if they are awarded a grant.
The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon Nuclear Security successfully ratified its CBA withoperates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the SPFPA Local 238 at Quad Citiesuse of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. The selection process is expected to an extensionbe highly competitive, and therefore, the Registrants cannot predict how many of three years. In June 2017, Exelon Nuclear Security successfully ratified its CBA withtheir total applications will be approved as filed or the UGSOA Local 12 at Limerick to an extensionprecise timing of three years.receiving any funds if they are awarded a grant.
Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of March 31, 2023, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2022. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATESCritical Accounting Policies and Estimates in Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's combined 2016the 2022 Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, goodwill, purchase accounting, unamortized energy assets and liabilities, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies, revenue recognition, and allowance for uncollectible accounts. At September 30, 2017, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2016.
further information.
Results of Operations By Registrant
Net Income (Loss) Attributable to Common Shareholders by Registrant
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2017 | | 2016 | | | 2017 | | 2016(a) | |
Exelon | $ | 824 |
| | $ | 490 |
| | $ | 334 |
| | $ | 1,899 |
| | $ | 930 |
| | $ | 969 |
|
Generation | 305 |
| | 236 |
| | 69 |
| | 479 |
| | 538 |
| | (59 | ) |
ComEd | 189 |
| | 37 |
| | 152 |
| | 447 |
| | 297 |
| | 150 |
|
PECO | 112 |
| | 122 |
| | (10 | ) | | 327 |
| | 346 |
| | (19 | ) |
BGE | 62 |
| | 54 |
| | 8 |
| | 231 |
| | 183 |
| | 48 |
|
Pepco | 87 |
| | 79 |
| | 8 |
| | 188 |
| | 20 |
| | 168 |
|
DPL | 31 |
| | 44 |
| | (13 | ) | | 107 |
| | (16 | ) | | 123 |
|
ACE | 41 |
| | 47 |
| | (6 | ) | | 77 |
| | (50 | ) | | 127 |
|
_________
| |
(a) | For Pepco, DPL and ACE, reflects that Registrant's operations for the nine months ended September 30, 2016. For Exelon and Generation, includes the operations of the PHI acquired businesses for the period of March 24, 2016 through September 30, 2016. |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 | | Nine Months Ended September 30, 2017 | | March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | | $ | 153 |
| | $ | 166 |
| | $ | 359 |
| | $ | (91 | ) | | | $ | 19 |
|
Results of Operations — GenerationComEd
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, | | (Unfavorable) Favorable Variance |
| | | | | | 2023 | | 2022 | |
Operating revenues | | | | | | | $ | 1,667 | | | $ | 1,734 | | | $ | (67) | |
Operating expenses | | | | | | | | | | | |
Purchased power | | | | | | | 488 | | | 638 | | | 150 | |
Operating and maintenance | | | | | | | 337 | | | 351 | | | 14 | |
Depreciation and amortization | | | | | | | 338 | | | 321 | | | (17) | |
Taxes other than income taxes | | | | | | | 93 | | | 96 | | | 3 | |
Total operating expenses | | | | | | | 1,256 | | | 1,406 | | | 150 | |
| | | | | | | | | | | |
Operating income | | | | | | | 411 | | | 328 | | | 83 | |
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | | | | | | | (117) | | | (100) | | | (17) | |
Other, net | | | | | | | 18 | | | 12 | | | 6 | |
Total other income and (deductions) | | | | | | | (99) | | | (88) | | | (11) | |
Income before income taxes | | | | | | | 312 | | | 240 | | | 72 | |
Income taxes | | | | | | | 71 | | | 52 | | | (19) | |
Net income | | | | | | | $ | 241 | | | $ | 188 | | | $ | 53 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating revenues | $ | 4,751 |
| | $ | 5,035 |
| | $ | (284 | ) | | $ | 13,812 |
| | $ | 13,363 |
| | $ | 449 |
|
Purchased power and fuel expense | 2,331 |
| | 2,589 |
| | 258 |
| | 7,286 |
| | 6,609 |
| | (677 | ) |
Revenues net of purchased power and fuel expense(a) | 2,420 |
| | 2,446 |
| | (26 | ) | | 6,526 |
| | 6,754 |
| | (228 | ) |
Other operating expenses | | | | | | | | | | | |
Operating and maintenance | 1,374 |
| | 1,336 |
| | (38 | ) | | 4,871 |
| | 4,333 |
| | (538 | ) |
Depreciation and amortization | 410 |
| | 632 |
| | 222 |
| | 1,046 |
| | 1,329 |
| | 283 |
|
Taxes other than income | 141 |
| | 136 |
| | (5 | ) | | 425 |
| | 380 |
| | (45 | ) |
Total other operating expenses | 1,925 |
| | 2,104 |
| | 179 |
| | 6,342 |
| | 6,042 |
| | (300 | ) |
(Loss) Gain on sales of assets | (2 | ) | | — |
| | (2 | ) | | 3 |
| | 31 |
| | (28 | ) |
Bargain purchase gain | 7 |
| | — |
| | 7 |
| | 233 |
| | — |
| | 233 |
|
Operating income | 500 |
|
| 342 |
| | 158 |
| | 420 |
|
| 743 |
| | (323 | ) |
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | (113 | ) | | (77 | ) | | (36 | ) | | (342 | ) | | (273 | ) | | (69 | ) |
Other, net | 209 |
| | 185 |
| | 24 |
| | 648 |
| | 395 |
| | 253 |
|
Total other income and (deductions) | 96 |
| | 108 |
| | (12 | ) | | 306 |
| | 122 |
| | 184 |
|
Income before income taxes | 596 |
| | 450 |
| | 146 |
| | 726 |
| | 865 |
| | (139 | ) |
Income taxes | 240 |
| | 173 |
| | (67 | ) | | 209 |
| | 293 |
| | 84 |
|
Equity in losses of unconsolidated affiliates | (8 | ) | | (6 | ) | | (2 | ) | | (26 | ) | | (16 | ) | | (10 | ) |
Net income | 348 |
|
| 271 |
|
| 77 |
|
| 491 |
|
| 556 |
|
| (65 | ) |
Net income attributable to noncontrolling interests | 43 |
| | 35 |
| | (8 | ) | | 12 |
| | 18 |
| | 6 |
|
Net income attributable to membership interest | $ | 305 |
| | $ | 236 |
| | $ | 69 |
| | $ | 479 |
| | $ | 538 |
| | $ | (59 | ) |
_________
| |
(a) | Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
Net Income Attributable to Membership Interest
Three Months Ended September 30, 2017March 31, 2023 Compared to Three Months Ended September 30, 2016. Generation’s March 31, 2022. Net income attributable to membership interest for the three months ended September 30, 2017 increased compared to the same period in 2016, primarily due to lower Depreciation and amortization expenses, a Bargain purchase gain in 2017, and higher other income, partially offset by lower Revenue net of purchased power and fuel expense, higher Operating and maintenance expenses, and higher interest expense. The decrease in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire Clinton and Quad Cities nuclear facilities. The Bargain purchase gain is primarily due to a measurement period adjustment for the FitzPatrick Acquisition. The increase in other income is primarily due to higher realized NDT fund gains. The decrease in Revenue net of purchased power and fuel expense primarily relates to the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, the acquisition of the FitzPatrick nuclear facility, a decrease in nuclear outage days, increased capacity prices, and the addition of the two combined-cycle gas turbines in Texas. The increase in Operating and maintenance is primarily due to the impairment of ExGen Texas Power in 2017. The increase in interest expense is primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Generation’s Net income attributable to membership interest for the nine months ended September 30, 2017 decreased compared to the same period in 2016, primarily due to lower Revenue net of purchased power and fuel expense, higher Operating and maintenance expenses, higher taxes other than income, and higher interest expense, partially offset by lower Depreciation and amortization, a bargain purchase gain in 2017, and higher other income. The decrease in Revenue net of purchased power and fuel expense primarily relates to the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation's natural gas portfolio, the impacts of lower load volumes due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, the acquisition of the FitzPatrick nuclear facility, increased capacity prices, the addition of two combined-cycle gas turbines in Texas, the absence of oil inventory write downs in 2017, and decreased fuel prices. The increase in operating and maintenance expenses primarily relates to the impairment of EGTP assets held for sale compared to the impairment of upstream assets and certain wind projects in 2016, an increase in the number of nuclear outage days in 2017 and increased salaries, wages and contracting costs related to the acquisition of the FitzPatrick nuclear facility. The increase in taxes other than income relates to increased sales and use tax, increased gross receipts tax, and increased property taxes due to the FitzPatrick Acquisition. The increase in interest expense is primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt. The decrease in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire Clinton and Quad Cities nuclear facilities. The bargain purchase gain is the result of the FitzPatrick acquisition in Q1 2017. The increase in other income is primarily due to increased unrealized gains on NDT funds in 2017 compared to 2016.
Revenues Net of Purchased Power and Fuel Expense
The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:
Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.
Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.
New York represents operations within ISO-NY, which covers the state of New York in its entirety.
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
The following business activities are not allocated to a region, and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, the following activities are not allocated to a region, and are reported in Other: amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.
Generation evaluates the operating performance of its electric business activities using the measure of Revenue net of purchased power and fuel expense, which is a non-GAAP measurement. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.
For the three and nine months ended September 30, 2017 and 2016, Generation’s Revenue net of purchased power and fuel expense by region were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Variance | | % Change | | Nine Months Ended September 30, | | Variance | | % Change |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Mid-Atlantic(a) | $ | 855 |
| | $ | 887 |
| | $ | (32 | ) | | (3.6 | )% | | $ | 2,411 |
| | $ | 2,556 |
| | $ | (145 | ) | | (5.7 | )% |
Midwest(b) | 697 |
| | 781 |
| | (84 | ) | | (10.8 | )% | | 2,140 |
| | 2,229 |
| | (89 | ) | | (4.0 | )% |
New England | 145 |
| | 160 |
| | (15 | ) | | (9.4 | )% | | 403 |
| | 350 |
| | 53 |
| | 15.1 | % |
New York(d) | 296 |
| | 194 |
| | 102 |
| | 52.6 | % | | 678 |
| | 592 |
| | 86 |
| | 14.5 | % |
ERCOT | 118 |
| | 93 |
| | 25 |
| | 26.9 | % | | 258 |
| | 231 |
| | 27 |
| | 11.7 | % |
Other Power Regions | 68 |
| | 77 |
| | (9 | ) | | (11.7 | )% | | 220 |
| | 253 |
| | (33 | ) | | (13.0 | )% |
Total electric revenue net of purchased power and fuel expense | 2,179 |
| | 2,192 |
| | (13 | ) | | (0.6 | )% | | 6,110 |
| | 6,211 |
| | (101 | ) | | (1.6 | )% |
Proprietary Trading | 4 |
| | 3 |
| | 1 |
| | 33.3 | % | | 11 |
| | 9 |
| | 2 |
| | 22.2 | % |
Mark-to-market (losses) gains | 73 |
| | 88 |
| | (15 | ) | | (17.0 | )% | | (161 | ) | | (113 | ) | | (48 | ) | | 42.5 | % |
Other(c) | 164 |
| | 163 |
| | 1 |
| | 0.6 | % | | 566 |
| | 647 |
| | (81 | ) | | (12.5 | )% |
Total revenue net of purchased power and fuel expense | $ | 2,420 |
| | $ | 2,446 |
| | $ | (26 | ) | | (1.1 | )% | | $ | 6,526 |
| | $ | 6,754 |
| | $ | (228 | ) | | (3.4 | )% |
_________
| |
(a) | Results of transactions with PECO and BGE are included in the Mid-Atlantic region. Results of transactions with Pepco, DPL, and ACE are included in the Mid-Atlantic region beginning on March 24, 2016, the day after the PHI merger was completed. |
| |
(b) | Results of transactions with ComEd are included in the Midwest region. |
| |
(c) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $19 million and $22 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $6 million and $28 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of a $41 million and $15 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $8 million and $38 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively. |
| |
(d) | Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017. |
Generation’s supply sources by region are summarized below:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Variance | | % Change | | Nine Months Ended September 30, | | Variance | | % Change |
Supply source (GWhs) | 2017 | | 2016 | | | 2017 | | 2016 | |
Nuclear generation | | | | | | | | | | | | | | | |
Mid-Atlantic(a) | 16,480 |
| | 15,604 |
| | 876 |
| | 5.6 | % | | 48,271 |
| | 47,035 |
| | 1,236 |
| | 2.6 | % |
Midwest | 24,362 |
| | 24,262 |
| | 100 |
| | 0.4 | % | | 69,422 |
| | 70,925 |
| | (1,503 | ) | | (2.1 | )% |
New York(a)(d) | 6,905 |
| | 4,843 |
| | 2,062 |
| | 42.6 | % | | 17,623 |
| | 14,002 |
| | 3,621 |
| | 25.9 | % |
Total Nuclear Generation | 47,747 |
| | 44,709 |
| | 3,038 |
| | 6.8 | % | | 135,316 |
|
| 131,962 |
| | 3,354 |
| | 2.5 | % |
Fossil and Renewables | | | | | | | | | | | | |
|
| |
|
|
Mid-Atlantic | 596 |
| | 706 |
| | (110 | ) | | (15.6 | )% | | 2,330 |
| | 2,290 |
| | 40 |
| | 1.7 | % |
Midwest | 218 |
| | 273 |
| | (55 | ) | | (20.1 | )% | | 1,053 |
| | 1,046 |
| | 7 |
| | 0.7 | % |
New England | 1,919 |
| | 1,886 |
| | 33 |
| | 1.7 | % | | 5,921 |
| | 5,826 |
| | 95 |
| | 1.6 | % |
New York | 1 |
| | 1 |
| | — |
| | — | % | | 3 |
| | 3 |
| | — |
| | — | % |
ERCOT | 5,703 |
| | 2,472 |
| | 3,231 |
| | 130.7 | % | | 9,388 |
| | 5,726 |
| | 3,662 |
| | 64.0 | % |
Other Power Regions | 2,149 |
| | 2,103 |
| | 46 |
| | 2.2 | % | | 5,656 |
| | 6,245 |
| | (589 | ) | | (9.4 | )% |
Total Fossil and Renewables | 10,586 |
| | 7,441 |
| | 3,145 |
| | 42.3 | % | | 24,351 |
|
| 21,136 |
| | 3,215 |
| | 15.2 | % |
Purchased Power | | | | | | | | | | | | |
|
| |
|
|
Mid-Atlantic | 2,541 |
| | 7,139 |
| | (4,598 | ) | | (64.4 | )% | | 8,840 |
| | 14,024 |
| | (5,184 | ) | | (37.0 | )% |
Midwest | 217 |
| | 461 |
| | (244 | ) | | (52.9 | )% | | 1,018 |
| | 1,855 |
| | (837 | ) | | (45.1 | )% |
New England | 4,513 |
| | 3,927 |
| | 586 |
| | 14.9 | % | | 13,920 |
| | 11,863 |
| | 2,057 |
| | 17.3 | % |
New York | — |
| | — |
| | — |
| | — | % | | 28 |
| | — |
| | 28 |
| | — | % |
ERCOT | 1,199 |
| | 2,895 |
| | (1,696 | ) | | (58.6 | )% | | 5,724 |
| | 7,448 |
| | (1,724 | ) | | (23.1 | )% |
Other Power Regions | 3,982 |
| | 3,803 |
| | 179 |
| | 4.7 | % | | 10,357 |
| | 10,281 |
| | 76 |
| | 0.7 | % |
Total Purchased Power | 12,452 |
| | 18,225 |
| | (5,773 | ) | | (31.7 | )% | | 39,887 |
|
| 45,471 |
| | (5,584 | ) | | (12.3 | )% |
Total Supply/Sales by Region(b) | | | | | | | | | | | | |
|
| |
|
|
Mid-Atlantic(c) | 19,617 |
| | 23,449 |
| | (3,832 | ) | | (16.3 | )% | | 59,441 |
| | 63,349 |
| | (3,908 | ) | | (6.2 | )% |
Midwest(c) | 24,797 |
| | 24,996 |
| | (199 | ) | | (0.8 | )% | | 71,493 |
| | 73,826 |
| | (2,333 | ) | | (3.2 | )% |
New England | 6,432 |
| | 5,813 |
| | 619 |
| | 10.6 | % | | 19,841 |
| | 17,689 |
| | 2,152 |
| | 12.2 | % |
New York | 6,906 |
| | 4,844 |
| | 2,062 |
| | 42.6 | % | | 17,654 |
| | 14,005 |
| | 3,649 |
| | 26.1 | % |
ERCOT | 6,902 |
| | 5,367 |
| | 1,535 |
| | 28.6 | % | | 15,112 |
| | 13,174 |
| | 1,938 |
| | 14.7 | % |
Other Power Regions | 6,131 |
| | 5,906 |
| | 225 |
| | 3.8 | % | | 16,013 |
| | 16,526 |
| | (513 | ) | | (3.1 | )% |
Total Supply/Sales by Region | 70,785 |
| | 70,375 |
| | 410 |
| | 0.6 | % | | 199,554 |
|
| 198,569 |
| | 985 |
| | 0.5 | % |
_________
| |
(a) | Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG). |
| |
(b) | Excludes physical proprietary trading volumes of 2,601 GWhs and 1,506 GWhs for the three months ended September 30, 2017 and 2016, respectively, and 6,763 GWhs and 4,015 GWhs for the nine months ended September 30, 2017 and 2016. |
| |
(c) | Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016. |
| |
(d) | Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017. |
Mid-Atlantic
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $32 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes and lower realized energy prices, partially offset by decreased nuclear outage days and increased capacity prices.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $145 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes, lower realized energy prices and decreased capacity prices, partially offset by the absence of oil inventory write-downs in 2017 and decreased nuclear outage days.
Midwest
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $84 million decrease in Revenue net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices, partially offset by increased capacity prices and decreased nuclear fuel prices.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $89 million decrease in Revenue net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices and increased nuclear outage days, partially offset by decreased fuel prices.
New England
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $15 million decrease in Revenue net of purchased power and fuel expense in New England primarily reflects lower realized energy prices, partially offset by increased capacity prices.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $53 million increase in Revenue net of purchased power and fuel expense in New England was driven by increased capacity prices, partially offset by lower realized energy prices.
New York
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $102 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to the impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $86 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.
ERCOT
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $25 million increase in Revenue net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $27 million increase in Revenue net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas, partially offset by lower realized energy prices.
Other Power Regions
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $9 million decrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $33 million decrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.
Proprietary Trading
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $1 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $2 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.
Mark-to-market
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. Mark-to-market gains on economic hedging activities were $73 million for the three months ended September 30, 2017 compared to gains of $88 million for the three months ended September 30, 2016. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Mark-to-market losses on economic hedging activities were $161 million for the nine months ended September 30, 2017 compared to losses of $113 million for the nine months ended September 30, 2016. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
Other
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $1 million increase in Revenue net of purchased power and fuel expense in Other was due to the decline in revenues related to the distributed generation business, offset by lower accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $81 million decrease in other revenue net of purchased power and fuel was primarily due to the impacts of declining natural gas prices on Generation’s natural gas portfolio and amortization of energy contracts recorded at fair value associated with prior acquisitions, partially offset by revenue related to the inclusion of Pepco Energy Services results in 2017 and lower accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.
Nuclear Fleet Capacity Factor
The following table presents nuclear fleet operating data for the three and nine months ended September 30, 2017 as compared to the same period in 2016, for the Generation-operated plants. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Nuclear fleet capacity factor(a) | 96.1 | % | | 96.3 | % | | 93.7 | % | | 94.8 | % |
Refueling outage days(a) | 13 |
| | 17 |
| | 233 |
| | 174 |
|
Non-refueling outage days(a) | 15 |
| | — |
| | 35 |
| | 31 |
|
_________
| |
(a) | Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017. |
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The nuclear fleet capacity factor decreased2022, primarily due to more non-refueling outage days and was partially offset by fewer refueling outage days, excluding Salem outages, during the three months ended September 30, 2017 compared to the same periodincreases in 2016.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The nuclear fleet capacity factor decreased primarily due to more refueling and non-refueling outage days, excluding Salem outages, during the nine months ended September 30, 2017 compared to the same period in 2016.
Operating and Maintenance
The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 as compared to the same period in 2016, consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| Increase (Decrease)(a) | | Increase (Decrease)(a) |
Labor, other benefits, contracting, materials(b) | $ | (8 | ) | | $ | 74 |
|
Nuclear refueling outage costs, including the co-owned Salem plants(c) | (12 | ) | | 88 |
|
Corporate allocations | 19 |
| | 29 |
|
Merger and integration costs(d) | (4 | ) | | 36 |
|
Merger commitments | — |
| | (3 | ) |
Plant retirements and divestitures(e) | 41 |
| | (15 | ) |
Cost management program | 5 |
| | (7 | ) |
ARO update | (3 | ) | | (4 | ) |
Long-lived asset impairments(f) | 25 |
| | 288 |
|
Pension and non-pension postretirement benefits expense | 3 |
| | 4 |
|
Allowance for uncollectible accounts | 12 |
| | 35 |
|
Accretion expense(g) | 10 |
| | 27 |
|
Other | (50 | ) | | (14 | ) |
Increase in operating and maintenance expense | $ | 38 |
| | $ | 538 |
|
_________
| |
(a) | The 2017 financial results include Generation's acquisition of the FitzPatrick nuclear generating station from March 31, 2017. |
| |
(b) | Reflects increased salaries, wages and contracting costs primarily related to the acquisition of the FitzPatrick nuclear facility beginning on March 31, 2017. |
| |
(c) | Primarily reflects a decrease in the number of nuclear outage days for the three months ended September 30, 2017 compared to 2016 and an increase in the number of nuclear outage days for the nine months ended September 30, 2017 compared to the same period in 2016. |
| |
(d) | Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions. |
| |
(e) | Represents the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016. |
| |
(f) | Primarily reflects charges to earnings related to impairments as a result of the EGTP assets held for sale in 2017 and impairment of Upstream assets and certain wind projects in 2016. |
| |
(g) | Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017. |
Depreciation and Amortization
Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 decreased primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities.
Taxes Other Than Income
Taxes other than income taxes, which can vary period to period, include non-income municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to increased property
taxes as a result of the addition of FitzPatrick, increased gross receipts tax expense, and increased sales and use tax expense.
(Loss) gain on Sales of Assets
Loss on sales of assets for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 remained relatively stable. Gain on sales of assets for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 decreased primarily due to the gain associated with Generation's sale of the New Boston generating site in 2016.
Bargain Purchase Gain
Bargain purchase gain for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased as a result of the gain associated with the FitzPatrick acquisition. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.
Interest Expense, net
Interest expense, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt.
Other, Net
Other, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to the change in the realized and unrealized gains and losses related to NDT funds of Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $37 million and $39 million for the three months ended September 30, 2017 and 2016, respectively, and $129 million and $84 million for the nine months ended September 30, 2017 and 2016, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. Refer to Note 13 — Nuclear Decommissioning of the Combined Notes to the Consolidated Financial Statements for additional information regarding NDT funds.
The following table provides unrealized and realized gains and losses on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for the three and nine months ended September 30, 2017 and 2016:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Net unrealized gains on decommissioning trust funds | $ | 111 |
|
| $ | 116 |
| | $ | 347 |
| | $ | 216 |
|
Net realized gains on sale of decommissioning trust funds | 33 |
| | 12 |
| | 82 |
| | 26 |
|
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates for the three and nine months ended September 30, 2017 compared to the three and nine ended September 30, 2016 remained relatively stable.
Effective Income Tax Rate
Generation's effective income tax rate was 40.3% and 38.4% for the three months ended September 30, 2017 and 2016, respectively. Generation's effective income tax rate was 28.8% and 33.9% for the nine months ended September 30, 2017 and 2016, respectively. See Note 12 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
Results of Operations — ComEd
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating revenues | $ | 1,571 |
| | $ | 1,497 |
| | $ | 74 |
| | $ | 4,227 |
| | $ | 4,031 |
| | $ | 196 |
|
Purchased power expense | 529 |
| | 454 |
| | (75 | ) | | 1,241 |
| | 1,141 |
| | (100 | ) |
Revenues net of purchased power expense(a)(b) | 1,042 |
| | 1,043 |
| | (1 | ) | | 2,986 |
| | 2,890 |
| | 96 |
|
Other operating expenses | | | | | | | | | | | |
Operating and maintenance | 346 |
| | 377 |
| | 31 |
| | 1,096 |
| | 1,113 |
| | 17 |
|
Depreciation and amortization | 212 |
| | 196 |
| | (16 | ) | | 631 |
| | 574 |
| | (57 | ) |
Taxes other than income | 80 |
| | 82 |
| | 2 |
| | 223 |
| | 222 |
| | (1 | ) |
Total other operating expenses | 638 |
| | 655 |
| | 17 |
| | 1,950 |
| | 1,909 |
| | (41 | ) |
Gain on sales of assets | — |
| | 1 |
| | (1 | ) | | — |
| | 6 |
| | (6 | ) |
Operating income | 404 |
| | 389 |
| | 15 |
| | 1,036 |
| | 987 |
| | 49 |
|
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | (89 | ) | | (197 | ) | | 108 |
| | (275 | ) | | (374 | ) | | 99 |
|
Other, net | 5 |
| | (80 | ) | | 85 |
| | 14 |
| | (72 | ) | | 86 |
|
Total other income and (deductions) | (84 | ) | | (277 | ) | | 193 |
| | (261 | ) | | (446 | ) | | 185 |
|
Income before income taxes | 320 |
| | 112 |
| | 208 |
| | 775 |
| | 541 |
| | 234 |
|
Income taxes | 131 |
| | 75 |
| | (56 | ) | | 328 |
| | 244 |
| | (84 | ) |
Net income | $ | 189 |
| | $ | 37 |
| | $ | 152 |
| | $ | 447 |
| | $ | 297 |
| | $ | 150 |
|
_________
| |
(a) | ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
| |
(b) | For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings). |
Net Income
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. ComEd’s Net income for the three months ended September 30, 2017 was higher than the same period in 2016, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016 and increased electric distribution and transmission formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of increased capital investmenthigher rate base) and higher allowed electric distribution ROE). The higher Net income was partially offset by the impact of weather conditions in the third quarter of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. ComEd’s Net income for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penaltycarrying costs related to the Tax Court's decision on Exelon's like-kind exchange tax positionCMC regulatory assets.
The changes in the third quarter of 2016 and increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset by additional tax and interest recorded in the second quarter of 2017 relating to Exelon's like-kind exchange tax position and the impact of weather conditions in the second and third quarters of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.
Revenues Net of Purchased Power Expense
There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity, REC, and ZEC procurement costs from retail customers without mark-up. Therefore, these costs have no significant impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information on ComEd’s electricity procurement process.
All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenues related to supplied energy, which is fully offset in Purchased power expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2017 and 2016, consisted of the following:
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Electric | 68 | % | | 70 | % | | 70 | % | | 72 | % |
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:
|
| | | | | | | | | | | |
| September 30, 2017 | | September 30, 2016 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 1,360,800 |
| | 34 | % | | 1,526,900 |
| | 39 | % |
The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2017, compared to the same period in 2016 consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Weather(a) | $ | (34 | ) | | $ | (37 | ) |
Volume(a) | (5 | ) | | (11 | ) |
Electric distribution revenue | 59 |
| | 119 |
|
Transmission revenue | 11 |
| | 45 |
|
Energy efficiency revenue(b) | 5 |
| | 6 |
|
Regulatory required programs(b) | (39 | ) | | (24 | ) |
Uncollectible accounts recovery, net | (3 | ) | | (5 | ) |
Pricing and customer mix(a) | — |
| | (1 | ) |
Other | 5 |
| | 4 |
|
Total increase (decrease) | $ | (1 | ) | | $ | 96 |
|
_________
| | | | | | | |
(a) | These changes only reflect the 2016 impacts of weather, volume, and pricing and customer mix. As further described below, pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer. | | Three Months Ended March 31, 2023 |
| | | Increase (Decrease) |
Distribution | | | $ | 111 | |
(b)Transmission | Beginning on June 1, 2017, ComEd is deferring energy | | (12) | |
Energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures. | | | 14 | |
Other | | | 2 | |
| | | 115 | |
Regulatory required programs | | | (182) | |
Total decrease | | | $ | (67) | |
Revenue Decoupling.The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as "favorable weather conditions" because these weather conditions result in increased customer usage. Conversely, mild weather reduces demand.
Under EIMA, ComEd's electric distribution formula rate provided for an adjustment to future billings if its earned ROE fell outside a 50 bps collar of its allowed ROE, which partially eliminated the impacts of weather and load on ComEd's revenue. As allowed under FEJA, 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 aboveare not impacted by abnormal weather, usage per customer, or below normal weather, numbersnumber of customers or usage per customer. ComEd began recognizing the impactsas a result of this change beginning in the first quarter of 2017. During the threerevenue decoupling mechanisms implemented pursuant to FEJA.
Distribution Revenue. EIMA and nine months ended September 30, 2017, ComEd recorded a decrease to Electric distribution revenues of approximately $15 million and an increase to Electric distribution revenues of approximately $21 million, respectively, to eliminate weather and load impacts.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in ComEd's service territory with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the three and nine months ended September 30, 2017 and 2016, consisted of the following:
|
| | | | | | | | | | | | | | |
Heating and Cooling Degree-Days | | | | | % Change |
Three Months Ended September 30, | 2017 | | 2016 | | Normal | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 42 |
| | 23 |
| | 97 |
| | 82.6 | % | | (56.7 | )% |
Cooling Degree-Days | 699 |
| | 840 |
| | 641 |
| | (16.8 | )% | | 9.0 | % |
| | | | | | | | | |
Nine Months Ended September 30, | | | | | | | | | |
Heating Degree-Days | 3,269 |
| | 3,678 |
| | 3,972 |
| | (11.1 | )% | | (17.7 | )% |
Cooling Degree-Days | 962 |
| | 1,130 |
| | 882 |
| | (14.9 | )% | | 9.1 | % |
Electric Distribution Revenue. EIMA providesFEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under EIMA, electricElectric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. In addition, ComEd's allowed ROE is subject to reduction if ComEd does not deliver the reliability and customer service benefits to which it has committed over the ten-year life of the investment program. Electric distribution revenue increased duringfor the three and nine months ended September 30, 2017, primarilyMarch 31, 2023 as compared to the same period in 2022, due to increased capital investment, increased Depreciation expense, and higher allowed ROE due to an increase in treasuryU.S. Treasury rates, as compared to the same period in 2016impact of a higher rate base, and due to revenue decoupling impacts (as described above) during the nine months ended September 30, 2017. See Depreciation and amortization expense discussions below, and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.higher fully recoverable costs.
Transmission Revenue.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak
load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. For the three and nine months ended September 30, 2017, ComEd recorded increased transmission revenue due to increased capital investment, higher Depreciation expense and increased highest daily peak load as compared to the same period in 2016. See Operating and maintenance expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. Beginning June 1, 2017, FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROEEnergy efficiency revenue increased for the three months ended March 31, 2023 as compared to the same period in 2022, primarily due to increased regulatory asset amortization, which is fully recoverable.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE is subjectthree months ended March 31, 2023 as compared 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 incrementalthe same period in 2022, which primarily reflects mutual assistance revenues associated with storm restoration efforts.
savings goal.Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. See Depreciation and amortization expense discussions below, and Note 53 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the changeinformation regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Operating revenues collected under approved rate ridersIllinois established by CEJA and remitted to recover costs incurredan Illinois state agency for regulatory programs such as ComEd’s purchased power administrative coststo support clean energy jobs and energy efficiency and demand response through June 1, 2017 pursuant to FEJA.training. The riders are designed to provide full and current cost recovery. An equal and offsetting amount has beenThe costs of these programs are included in Operating and maintenance expense. SeePurchased power expense, Operating and maintenance expense, discussion belowDepreciation and amortization expense and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for additional information on included programs.
Uncollectible Accounts Recovery, Net. Uncollectible accounts recovery, net represents recoveries under ComEd’s uncollectible accounts tariff. Seeall customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and maintenancetherefore does not record Operating revenues or Purchased power expense discussion below for additional information on this tariff.
Other. Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance providedthe electricity. For customers that choose to other utilities through mutual assistance programs, recoveries of environmentalpurchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs associated with MGP sites,without mark-up and recoveries of energy procurement costs.
Operatingtherefore records equal and Maintenance Expense
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Increase (Decrease) | | Nine Months Ended September 30, | | Increase (Decrease) |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating and maintenance expense — baseline | $ | 344 |
| | $ | 336 |
| | $ | 8 |
| | $ | 1,000 |
| | $ | 993 |
| | $ | 7 |
|
Operating and maintenance expense — regulatory required programs(a) | 2 |
| | 41 |
| | $ | (39 | ) | | 96 |
| | 120 |
| | (24 | ) |
Total operating and maintenance expense | $ | 346 |
|
| $ | 377 |
|
| $ | (31 | ) |
| $ | 1,096 |
|
| $ | 1,113 |
|
| $ | (17 | ) |
_________
| |
(a) | Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues. |
The increaseoffsetting amounts in Operating revenues and maintenancePurchased power expense related to the electricity, ZECs, CMCs, and RECs.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The decrease of $150 million for the three and nine months ended September 30, 2017March 31, 2023 compared to the same period in 2016,2022, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities including the deferral of any associated carrying costs. This favorability is offset by a decrease in Operating revenues as part of regulatory required programs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs.
The changes in Operating and maintenance expense consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Baseline | | | |
Labor, other benefits, contracting and materials | $ | (5 | ) | | $ | (11 | ) |
Pension and non-pension postretirement benefits expense | 1 |
| | 2 |
|
Storm-related costs | 1 |
| | 1 |
|
Uncollectible accounts expense — provision(a) | (4 | ) | | (8 | ) |
Uncollectible accounts expense — recovery, net(a) | 1 |
| | 3 |
|
BSC costs(b) | 21 |
| | 35 |
|
Other | (7 | ) | | (15 | ) |
| 8 |
| | 7 |
|
Regulatory required programs | | | |
Energy efficiency and demand response programs(c) | (39 | ) | | (24 | ) |
Decrease in operating and maintenance expense | $ | (31 | ) | | $ | (17 | ) |
_________
| | | | | | | |
(a) | ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and nine months ended September 30, 2017, ComEd recorded a net decrease in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting decrease has been recognized in Operating revenues for the period presented. | | Three Months Ended March 31, 2023 |
| | | Increase (Decrease) |
| | | |
(b)Labor, other benefits, contracting and materials | For the three | | $ | 17 | |
Storm-related costs | | | 1 | |
Pension and nine months ended September 30, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected.non-pension postretirement benefits expense | | | (4) | |
| | | |
(c)BSC costs | Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures. | | (2) | |
| | | |
Other(a) | | | (8) | |
| | | 4 | |
Regulatory required programs(b) | | | (18) | |
Total decrease | | | $ | (14) | |
__________
(a)For the three months ended March 31, 2023, the decrease is primarily due to the voluntary customer refund made in 2022 related to the ICC investigation of matters identified in the Deferred Prosecution Agreement. See Note 12 —
Commitments and Contingenciesof the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.
Depreciation(b)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and Amortization Expensethe amounts collected in rates annually through a rider mechanism.
The increasechanges in Depreciation and amortization expense duringconsisted of the following:
| | | | | | | |
| | | Three Months Ended March 31, 2023 |
| | | Increase |
Depreciation and amortization(a) | | | $ | 13 | |
Regulatory asset amortization(b) | | | 4 | |
| | | |
Total increase | | | $ | 17 | |
__________
(a)Reflects ongoing capital expenditures and higher depreciation rates effective January 2023.
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Interest expense, net increased by $17 million for the three and nine months ended September 30, 2017,March 31, 2023, compared to the same period in 2016, consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Depreciation expense(a) | $ | 14 |
| | $ | 47 |
|
Regulatory asset amortization(b) | 1 |
| | 2 |
|
Other | 1 |
| | 8 |
|
Total increase | $ | 16 |
| | $ | 57 |
|
_________
| |
(a) | Primarily reflects ongoing capital expenditures for the three and nine months ended September 30, 2017. |
| |
(b) | Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset. |
Taxes Other Than Income
Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes remained relatively consistent for the three and nine months ended September 30, 2017, compared to the same period in 2016.
Gain on Sales of Assets
The decrease in Gain on sales of assets during the nine months ended September 30, 2017, compared to the same period in 2016, is2022, primarily due to the sale of land during March 2016.
Interest Expense, Net
The changesan increase in interest expense, net, forrates and the three and nine months ended September 30, 2017, compared to the same period in 2016, consistedissuance of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Interest expense related to uncertain tax positions(a) | $ | (110 | ) | | $ | (103 | ) |
Interest expense on debt (including financing trusts) | (1 | ) | | 3 |
|
Other | 3 |
| | 1 |
|
Decrease in interest expense, net | $ | (108 | ) | | $ | (99 | ) |
_________
| |
(a) | Primarily reflects the recognition of the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016, partially offset by additional interest recorded in the second quarter of 2017 related to Exelon's like-kind exchange tax position. |
Other, Net
Other, net, decreaseddebt during the three and nine months ended September 30, 2017, compared to the same period in 2016 primarily due to the recognition of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016.year.
Effective Income Tax Rate
ComEd's effective income tax rate was 40.9%rates were 22.8% and 67.0%21.7% for the three months ended September 30, 2017March 31, 2023 and 2016,2022, respectively. ComEd's effective income tax rate was 42.3% and 45.1% for the nine months ended September 30, 2017 and 2016, respectively. The decreases in the effective income tax rates for the three and nine months ended September 30, 2017 as compared to the same period in 2016 are primarily due to a non-deductible penalty incurred in 2016. See Note 127 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
ComEd Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Weather- Normal % Change | | Nine Months Ended September 30, | | % Change | | Weather- Normal % Change |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Deliveries(a) | | | | | | | | | | | | | | | |
Residential | 8,004 |
| | 9,014 |
| | (11.2 | )% | | (0.6 | )% | | 20,164 |
| | 21,738 |
| | (7.2 | )% | | (1.3 | )% |
Small commercial & industrial | 8,488 |
| | 8,833 |
| | (3.9 | )% | | (1.0 | )% | | 23,634 |
| | 24,447 |
| | (3.3 | )% | | (1.6 | )% |
Large commercial & industrial | 7,232 |
| | 7,565 |
| | (4.4 | )% | | (2.5 | )% | | 20,712 |
| | 21,057 |
| | (1.6 | )% | | (0.5 | )% |
Public authorities & electric railroads | 302 |
| | 308 |
| | (1.9 | )% | | (1.7 | )% | | 928 |
| | 947 |
| | (2.0 | )% | | (1.4 | )% |
Total retail deliveries | 24,026 |
|
| 25,720 |
| | (6.6 | )% | | (1.3 | )% | | 65,438 |
|
| 68,189 |
| | (4.0 | )% | | (1.1 | )% |
|
| | | | | |
| As of September 30, |
Number of Electric Customers | 2017 | | 2016 |
Residential | 3,610,091 |
| | 3,578,846 |
|
Small commercial & industrial | 376,309 |
| | 372,603 |
|
Large commercial & industrial | 1,954 |
| | 2,010 |
|
Public authorities & electric railroads | 4,763 |
| | 4,738 |
|
Total | 3,993,117 |
|
| 3,958,197 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
Electric Revenue | 2017 | | 2016 | | % Change | | 2017 | | 2016 | | % Change |
Retail Sales(a) | | | | | | | | | | | |
Residential | $ | 825 |
| | $ | 786 |
| | 5.0 | % | | $ | 2,108 |
| | $ | 2,018 |
| | 4.5 | % |
Small commercial & industrial | 369 |
| | 356 |
| | 3.7 | % | | 1,051 |
| | 1,007 |
| | 4.4 | % |
Large commercial & industrial | 121 |
| | 126 |
| | (4.0 | )% | | 352 |
| | 350 |
| | 0.6 | % |
Public authorities & electric railroads | 11 |
| | 10 |
| | 10.0 | % | | 34 |
| | 33 |
| | 3.0 | % |
Total retail | 1,326 |
| | 1,278 |
| | 3.8 | % | | 3,545 |
| | 3,408 |
| | 4.0 | % |
Other revenue(b) | 245 |
| | 219 |
| | 11.9 | % | | 682 |
| | 623 |
| | 9.5 | % |
Total electric revenue(c) | $ | 1,571 |
| | $ | 1,497 |
| | 4.9 | % | | $ | 4,227 |
| | $ | 4,031 |
| | 4.9 | % |
_________
| |
(a) | Reflects delivery revenue and volume from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission. |
| |
(b) | Other revenue primarily includes transmission revenue from PJM. Other revenue also includes rental revenue, revenue related to late payment charges, revenue from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites. |
| |
(c) | Includes operating revenues from affiliates totaling $3 million and $4 million for the three and nine months ended September 30, 2017 and 2016, and $12 million and $12 million for the nine months ended September 30, 2017 and 2016, respectively. |
Results of Operations — PECO
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, | | Favorable (Unfavorable) Variance |
| | | | | | 2023 | | 2022 | |
Operating revenues | | | | | | | $ | 1,112 | | | $ | 1,047 | | | $ | 65 | |
Operating expenses | | | | | | | | | | | |
Purchased power and fuel | | | | | | | 484 | | | 407 | | | (77) | |
Operating and maintenance | | | | | | | 270 | | | 247 | | | (23) | |
Depreciation and amortization | | | | | | | 98 | | | 92 | | | (6) | |
Taxes other than income taxes | | | | | | | 50 | | | 47 | | | (3) | |
Total operating expenses | | | | | | | 902 | | | 793 | | | (109) | |
| | | | | | | | | | | |
Operating income | | | | | | | 210 | | | 254 | | | (44) | |
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | | | | | | | (48) | | | (41) | | | (7) | |
Other, net | | | | | | | 8 | | | 7 | | | 1 | |
Total other income and (deductions) | | | | | | | (40) | | | (34) | | | (6) | |
Income before income taxes | | | | | | | 170 | | | 220 | | | (50) | |
Income taxes | | | | | | | 4 | | | 14 | | | 10 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Net income | | | | | | | $ | 166 | | | $ | 206 | | | $ | (40) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating revenues | $ | 715 |
| | $ | 788 |
| | $ | (73 | ) | | $ | 2,141 |
| | $ | 2,293 |
| | $ | (152 | ) |
Purchased power and fuel expense | 235 |
| | 272 |
| | 37 |
| | 719 |
| | 809 |
| | 90 |
|
Revenues net of purchased power and fuel expense(a) | 480 |
| | 516 |
| | (36 | ) | | 1,422 |
| | 1,484 |
| | (62 | ) |
Other operating expenses | | | | | | | | | | | |
Operating and maintenance | 197 |
| | 199 |
| | 2 |
| | 595 |
| | 604 |
| | 9 |
|
Depreciation and amortization | 72 |
| | 67 |
| | (5 | ) | | 213 |
| | 201 |
| | (12 | ) |
Taxes other than income | 42 |
| | 46 |
| | 4 |
| | 116 |
| | 126 |
| | 10 |
|
Total other operating expenses | 311 |
| | 312 |
| | 1 |
| | 924 |
| | 931 |
| | 7 |
|
Operating income | 169 |
| | 204 |
| | (35 | ) | | 498 |
| | 553 |
| | (55 | ) |
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | (31 | ) | | (30 | ) | | (1 | ) | | (93 | ) | | (92 | ) | | (1 | ) |
Other, net | 2 |
| | 2 |
| | — |
| | 6 |
| | 6 |
| | — |
|
Total other income and (deductions) | (29 | ) | | (28 | ) | | (1 | ) | | (87 | ) | | (86 | ) | | (1 | ) |
Income before income taxes | 140 |
| | 176 |
| | (36 | ) | | 411 |
| | 467 |
| | (56 | ) |
Income taxes | 28 |
| | 54 |
| | 26 |
| | 84 |
| | 121 |
| | 37 |
|
Net income | $ | 112 |
| | $ | 122 |
| | $ | (10 | ) | | $ | 327 |
| | $ | 346 |
| | $ | (19 | ) |
_________
| |
(a) | PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not presentations defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report. |
Net Income
Three Months Ended September 30, 2017March 31, 2023 Compared to Three Months Ended September 30, 2016. PECO'sMarch 31, 2022. Net income decreased from the same period in 2016, by $40 million, primarily due to lower Revenues net of purchased power and fuel from unfavorable weather conditionsand credit loss expense, partially offset by an increase in PECO's service territory.gas distribution rates.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. PECO's Net income decreased from the same periodThe changes in 2016, primarily due to lower Revenues net of purchased power and fuel from unfavorable weather conditions in PECO's service territory.
Revenues Net of Purchased Power and Fuel Expense
Electric and natural gas revenue and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. PECO's electric supply and natural gas cost rates charged to customers are subject to adjustments at least quarterly that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC's GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and natural gas revenue net of purchased power and fuel expense.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers' choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and natural gas revenue net of purchased power and fuel expense.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2017 and 2016,Operating revenues consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, 2023 |
| | | (Decrease) Increase |
| | | | | | | Electric | | Gas | | Total |
Weather | | | | | | | $ | (25) | | | $ | (25) | | | $ | (50) | |
Volume | | | | | | | (7) | | | 2 | | | (5) | |
Pricing | | | | | | | 11 | | | 23 | | | 34 | |
Transmission | | | | | | | (2) | | | — | | | (2) | |
Other | | | | | | | (1) | | | 6 | | | 5 | |
| | | | | | | (24) | | | 6 | | | (18) | |
Regulatory required programs | | | | | | | 78 | | | 5 | | | 83 | |
Total increase | | | | | | | $ | 54 | | | $ | 11 | | | $ | 65 | |
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Electric | 70 | % | | 69 | % | | 71 | % | | 70 | % |
Natural Gas | 29 | % | | 31 | % | | 26 | % | | 26 | % |
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:
|
| | | | | | | | | | | |
| September 30, 2017 | | September 30, 2016 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 570,500 |
| | 35 | % | | 581,600 |
| | 36 | % |
Natural Gas | 82,600 |
| | 16 | % | | 81,300 |
| | 16 | % |
The changes in PECO’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
| Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
Weather | $ | (48 | ) | | $ | — |
| | $ | (48 | ) | | $ | (45 | ) | | $ | (3 | ) | | $ | (48 | ) |
Volume | — |
| | 1 |
| | 1 |
| | (12 | ) | | 4 |
| | (8 | ) |
Pricing | 9 |
| | — |
| | 9 |
| | 13 |
| | — |
| | 13 |
|
Regulatory required programs | (6 | ) | | — |
| | (6 | ) | | (29 | ) | | — |
| | (29 | ) |
Other | 7 |
| | 1 |
| | 8 |
| | 10 |
| | — |
| | 10 |
|
Total decrease | $ | (38 | ) | | $ | 2 |
| | $ | (36 | ) | | $ | (63 | ) | | $ | 1 |
| | $ | (62 | ) |
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended September 30, 2017March 31, 2023 compared to the same period in 2016,2022, Operating revenue netrevenues related to weather decreased by the impact of purchased power decreased due to unfavorable summer weather conditions. Operating revenue net of fuel expense was relatively consistent. During the nine months ended September 30, 2017 compared to the same period in 2016, Operating revenue net of purchased power and fuel expense decreased due to unfavorable weather conditions.
conditions in PECO's service territory.
Heating and cooling degree daysdegree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree daysdegree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree daysdegree-days in
PECO’s service territory for the three and nine months ended September 30, 2017March 31, 2023 compared to the same periodsperiod in 20162022 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | | | % Change |
PECO Service Territory | 2023 | | 2022 | Normal | 2023 vs. 2022 | | 2023 vs. Normal |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | |
| | | | | | | | |
Heating Degree-Days | 1,888 | | | 2,228 | | 2,418 | | (15.3) | % | | (21.9) | % |
Cooling Degree-Days | — | | | 1 | | 1 | | (100.0) | % | | (100.0) | % |
|
| | | | | | | | | | | | | | |
Heating and Cooling Degree-Days | | | Normal | | % Change |
Three Months Ended September 30, | 2017 | | 2016 | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 14 |
| | 10 |
| | 35 |
| | 40.0 | % | | (60.0 | )% |
Cooling Degree-Days | 989 |
| | 1,288 |
| | 923 |
| | (23.2 | )% | | 7.2 | % |
| | | | | | | | | |
Nine Months Ended September 30, | | | | | | | | | |
Heating Degree-Days | 2,437 |
| | 2,616 |
| | 2,974 |
| | (6.8 | )% | | (18.1 | )% |
Cooling Degree-Days | 1,404 |
| | 1,684 |
| | 1,271 |
| | (16.6 | )% | | 10.5 | % |
Volume. Operating revenue net of purchased power and fuel related to delivery volume, exclusive of the effects of weather, remained relatively consistent for the three months ended September 30, 2017 compared to the same period in 2016. The decrease in Operating revenue net of purchased power related to deliveryElectric volume, exclusive of the effects of weather, for the ninethree months ended September 30, 2017March 31, 2023, compared to the same period in 2016, primarily reflects the impacts of energy efficiency initiatives on customer usage partially offset by moderate economic and customer growth, as well as a shift in the2022, remained relatively consistent. Natural gas volume profile across classes from residential and small commercial and industrial to large commercial and industrial. Operating revenue net of fuel expense for the ninethree months ended September 30, 2017March 31, 2023 compared to the same period in 2016 increased due to strong customer growth2022, remained relatively consistent.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Electric Retail Deliveries to Customers (in GWhs) | | | | | | | Three Months Ended March 31, | | % Change | | Weather - Normal % Change(b) |
| | | | | 2023 | | 2022 | |
Residential | | | | | | | | | 3,358 | | 3,758 | | (10.6) | % | | (0.1) | % |
Small commercial & industrial | | | | | | | | | 1,843 | | 1,937 | | (4.9) | % | | 0.4 | % |
Large commercial & industrial | | | | | | | | | 3,237 | | 3,332 | | (2.9) | % | | (1.2) | % |
Public authorities & electric railroads | | | | | | | | | 168 | | 182 | | (7.7) | % | | 9.3 | % |
Total electric retail deliveries(a) | | | | | | | | | 8,606 | | 9,209 | | (6.5) | % | | (0.2) | % |
| | | | | | | | | | | |
| As of March 31, |
Number of Electric Customers | 2023 | | 2022 |
Residential | 1,529,779 | | 1,521,255 |
Small commercial & industrial | 155,846 | | 155,485 |
Large commercial & industrial | 3,118 | | 3,102 |
Public authorities & electric railroads | 10,401 | | 10,342 |
Total | 1,699,144 | | 1,690,184 |
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and moderate economic growth.customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
Pricing. Operating revenues net(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural Gas Deliveries to Customers (in mmcf) | | | | | | | Three Months Ended March 31, | | % Change | | Weather - Normal % Change(b) |
| | | | | 2023 | | 2022 | |
Residential | | | | | | | | | 17,190 | | 20,837 | | (17.5) | % | | (2.4) | % |
Small commercial & industrial | | | | | | | | | 8,699 | | 10,546 | | (17.5) | % | | (3.4) | % |
Large commercial & industrial | | | | | | | | | 29 | | 10 | | 190.0 | % | | 21.7 | % |
Transportation | | | | | | | | | 7,014 | | 7,639 | | (8.2) | % | | (5.4) | % |
Total natural gas retail deliveries(a) | | | | | | | | | 32,932 | | 39,032 | | (15.6) | % | | (3.2) | % |
| | | | | | | | | | | |
| As of March 31, |
Number of Natural Gas Customers | 2023 | | 2022 |
Residential | 504,181 | | 499,188 |
Small commercial & industrial | 45,003 | | 44,959 |
Large commercial & industrial | 9 | | 5 |
Transportation | 650 | | 664 |
Total | 549,843 | | 544,816 |
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three and nine months ended September 30, 2017March 31, 2023 compared to the same period in 20162022 increased primarily due to higher overall effectivean increase in gas distribution rates duecharged to decreased usage acrosscustomers.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the major customer classes. Operating revenues net of fuel expenseunderlying costs and capital investments being recovered.
Other revenue primarily includes revenue related to late payment charges. Other revenue for the three and nine months ended September 30, 2017March 31, 2023 compared to the same period in 20162022 remained relatively consistent.
Regulatory Required Programs. This Programs represents the change in Operating revenuerevenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Refer to the Operating and maintenance expense discussion below for additional information on included programs.
Other. Other revenue, which can vary period to period, primarily includes wholesale transmission revenue, rental revenue, revenue related to late payment charges and assistance provided to other utilities through mutual assistance programs.
Operating and Maintenance Expense
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Increase (Decrease) | | Nine Months Ended September 30, | | Increase (Decrease) |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating and maintenance expense — baseline | $ | 183 |
| | $ | 185 |
| | $ | (2 | ) | | $ | 552 |
| | $ | 545 |
| | $ | 7 |
|
Operating and maintenance expense — regulatory required programs(a) | 14 |
| | 14 |
| | — |
| | 43 |
| | 59 |
| | (16 | ) |
Total operating and maintenance expense | $ | 197 |
| | $ | 199 |
| | $ | (2 | ) | | $ | 595 |
| | $ | 604 |
| | $ | (9 | ) |
_________
| |
(a) | Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues. |
The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Baseline | | | |
Labor, other benefits, contracting and materials | $ | 7 |
| | $ | 14 |
|
Storm-related costs | (3 | ) | | (7 | ) |
Pension and non-pension postretirement benefits expense | (1 | ) | | (2 | ) |
PHI merger and integration costs | 1 |
| | 1 |
|
BSC costs | 5 |
| | 6 |
|
Uncollectible accounts expense | (6 | ) | | (6 | ) |
Other | (5 | ) | | 1 |
|
| (2 | ) | | 7 |
|
Regulatory Required Programs | | | |
Energy efficiency | 1 |
| | (15 | ) |
Other | (1 | ) | | (1 | ) |
| — |
| | (16 | ) |
Total decrease | $ | (2 | ) | | $ | (9 | ) |
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Depreciation and amortization expense | $ | 5 |
| | $ | 13 |
|
Regulatory asset amortization | — |
| | (1 | ) |
Total increase | $ | 5 |
| | $ | 12 |
|
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income decreased for the three and nine months ended September 30, 2017 compared to the same period in 2016 due to a decrease in gross receipts tax driven by a decrease in electric revenue.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.
Other, Net
Other, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.
Effective Income Tax Rate
PECO's effective income tax rate was 20.0% and 30.7% for the three months ended September 30, 2017 and 2016, respectively, and 20.4% and 25.9% for the nine months ended September 30, 2017 and 2016, respectively. See
Note 12 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.
PECO Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Weather - Normal % Change | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Deliveries(a) | | | | | | | | | | | | | | | |
Residential | 3,752 |
| | 4,358 |
| | (13.9 | )% | | 0.2 | % | | 9,939 |
| | 10,682 |
| | (7.0 | )% | | (1.4 | )% |
Small commercial & industrial | 2,158 |
| | 2,324 |
| | (7.1 | )% | | (1.0 | )% | | 6,048 |
| | 6,236 |
| | (3.0 | )% | | (1.1 | )% |
Large commercial & industrial | 4,137 |
| | 4,234 |
| | (2.3 | )% | | 1.4 | % | | 11,593 |
| | 11,598 |
| | — | % | | 0.8 | % |
Public authorities & electric railroads | 198 |
| | 240 |
| | (17.5 | )% | | (17.5 | )% | | 618 |
| | 672 |
| | (8.0 | )% | | (8.0 | )% |
Total retail deliveries | 10,245 |
|
| 11,156 |
| | (8.2 | )% | | — | % | | 28,198 |
|
| 29,188 |
| | (3.4 | )% | | (0.6 | )% |
|
| | | | | |
| As of September 30, |
Number of Electric Customers | 2017 | | 2016 |
Residential | 1,463,906 |
| | 1,451,533 |
|
Small commercial & industrial | 150,964 |
| | 149,646 |
|
Large commercial & industrial | 3,112 |
| | 3,094 |
|
Public authorities & electric railroads | 9,665 |
| | 9,820 |
|
Total | 1,627,647 |
| | 1,614,093 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Nine Months Ended September 30, | | % Change |
Electric Revenue | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Sales(a) | | | | | | | | | | | |
Residential | $ | 434 |
| | $ | 513 |
| | (15.4 | )% | | $ | 1,147 |
| | $ | 1,278 |
| | (10.3 | )% |
Small commercial & industrial | 106 |
| | 109 |
| | (2.8 | )% | | 303 |
| | 334 |
| | (9.3 | )% |
Large commercial & industrial | 59 |
| | 59 |
| | — | % | | 168 |
| | 182 |
| | (7.7 | )% |
Public authorities & electric railroads | 7 |
| | 8 |
| | (12.5 | )% | | 23 |
| | 25 |
| | (8.0 | )% |
Total retail | 606 |
| | 689 |
| | (12.0 | )% | | 1,641 |
| | 1,819 |
| | (9.8 | )% |
Other revenue(b) | 56 |
| | 51 |
| | 9.8 | % | | 161 |
| | 152 |
| | 5.9 | % |
Total electric revenue(c) | $ | 662 |
| | $ | 740 |
| | (10.5 | )% | | $ | 1,802 |
| | $ | 1,971 |
| | (8.6 | )% |
_________
| |
(a) | Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission. |
| |
(b) | Other revenue primarily includes transmission revenue from PJM and wholesale electric revenue, in addition to rental income. |
| |
(c) | Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended September 30, 2017 and 2016, respectively, and $4 million and $5 million for the nine months ended September 30, 2017 and 2016, respectively. |
PECO Natural Gas Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Weather - Normal % Change | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change |
Deliveries to Customers (in mmcf) | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Delivery | | | | | | | | | | | | | | | |
Retail sales(a) | 3,993 |
| | 3,494 |
| | 14.3 | % | | 9.4 | % | | 38,825 |
| | 38,488 |
| | 0.9 | % | | 2.7 | % |
Transportation and other | 5,674 |
| | 7,315 |
| | (22.4 | )% | | (14.5 | )% | | 19,122 |
| | 20,917 |
| | (8.6 | )% | | (5.9 | )% |
Total natural gas deliveries | 9,667 |
| | 10,809 |
| | (10.6 | )% | | (6.0 | )% | | 57,947 |
| | 59,405 |
| | (2.5 | )% | | (0.1 | )% |
|
| | | | | |
| As of September 30, |
Number of Natural Gas Customers | 2017 | | 2016 |
Residential | 474,766 |
| | 470,024 |
|
Commercial & industrial | 43,358 |
| | 42,997 |
|
Total retail | 518,124 |
|
| 513,021 |
|
Transportation | 771 |
| | 802 |
|
Total | 518,895 |
|
| 513,823 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Nine Months Ended September 30, | | % Change |
Natural Gas Revenue | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Sales | | | | | | | | | | | |
Retail sales(a) | $ | 46 |
| | $ | 41 |
| | 12.2 | % | | $ | 315 |
| | $ | 298 |
| | 5.7 | % |
Transportation and other | 7 |
| | 7 |
| | — | % | | 24 |
| | 24 |
| | — | % |
Total natural gas revenues(b) | $ | 53 |
|
| $ | 48 |
| | 10.4 | % | | $ | 339 |
|
| $ | 322 |
| | 5.3 | % |
_________
| |
(a) | Reflects delivery volumes and revenue from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas. |
| |
(b) | Includes operating revenues from affiliates totaling less than $1 million for the three and nine months ended September 30, 2017 and 2016. |
Results of Operations — BGE |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating revenues | $ | 738 |
| | $ | 812 |
| | $ | (74 | ) | | $ | 2,363 |
| | $ | 2,421 |
| | $ | (58 | ) |
Purchased power and fuel expense | 269 |
| | 360 |
| | 91 |
| | 853 |
| | 994 |
| | 141 |
|
Revenues net of purchased power and fuel expense(a) | 469 |
| | 452 |
| | 17 |
| | 1,510 |
| | 1,427 |
| | 83 |
|
Other operating expenses | | | | | | | | | | | |
Operating and maintenance | 175 |
| | 178 |
| | 3 |
| | 532 |
| | 588 |
| | 56 |
|
Depreciation and amortization | 109 |
| | 101 |
| | (8 | ) | | 348 |
| | 307 |
| | (41 | ) |
Taxes other than income | 61 |
| | 58 |
| | (3 | ) | | 180 |
| | 172 |
| | (8 | ) |
Total other operating expenses | 345 |
| | 337 |
| | (8 | ) | | 1,060 |
| | 1,067 |
| | 7 |
|
Operating income | 124 |
| | 115 |
| | 9 |
| | 450 |
| | 360 |
| | 90 |
|
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | (26 | ) | | (28 | ) | | 2 |
| | (80 | ) | | (76 | ) | | (4 | ) |
Other, net | 4 |
| | 5 |
| | (1 | ) | | 12 |
| | 16 |
| | (4 | ) |
Total other income and (deductions) | (22 | ) | | (23 | ) | | 1 |
| | (68 | ) | | (60 | ) | | (8 | ) |
Income before income taxes | 102 |
| | 92 |
| | 10 |
| | 382 |
| | 300 |
| | 82 |
|
Income taxes | 40 |
| | 36 |
| | (4 | ) | | 151 |
| | 109 |
| | (42 | ) |
Net income | 62 |
| | 56 |
| | 6 |
| | 231 |
| | 191 |
| | 40 |
|
Preference stock dividends | — |
| | 2 |
| | 2 |
| | — |
| | 8 |
| | 8 |
|
Net income attributable to common shareholder | $ | 62 |
| | $ | 54 |
| | $ | 8 |
| | $ | 231 |
| | $ | 183 |
| | $ | 48 |
|
_________
| |
(a) | BGE evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. BGE believes revenues net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenues net of purchased power and fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report. |
Net Income Attributable to Common Shareholder
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. BGE’s Net income attributable to common shareholder for the three months ended September 30, 2017 was higher than the same period in 2016, primarily due to an increase in Revenues net of purchased power and fuel expense, predominantly as a result of an increase in transmission formula rate revenues. This item was partially offset by an increase in Depreciation and amortization expense primarily related to the impacts of increased capital investment.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. BGE’s Net income attributable to common shareholder for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily due to an increase in Revenues net of purchased power and fuel expense and lower Operating and maintenance expense. The increase in Revenues net of purchased power and fuel expense was primarily due to the impacts of the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues. The lower Operating and maintenance expense was primarily due to the absence of cost disallowances resulting from the 2016 distribution rate orders issued by the MDPSC and decreased storm costs in 2017. These items were partially offset by higher income tax expense primarily resulting from a cumulative adjustment to reduce tax expense in 2016 for transmission-related regulatory assets and an increase in Depreciation and amortization expense primarily related to the initiation of cost recovery of the AMI programs under the distribution rate orders and the impacts of increased capital investment.
Revenues Net of Purchased Power and Fuel Expense
There are certain drivers to Operating revenues that are offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Operating revenues and Purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in the number of customers electing to use a competitive electric generation or natural gas supplier. All BGE customersCustomers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers'suppliers. Customer choice of suppliers doesprograms do not impact the volume of deliveries but does affect revenue collected fromas PECO remains the distribution service provider for all customers relatedand charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to supplied energy and natural gas.
Retail deliveries purchased from competitivepurchase electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2017 and 2016 consisted of the following:
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Electric | 60 | % | | 58 | % | | 60 | % | | 59 | % |
Natural Gas | 74 | % | | 80 | % | | 57 | % | | 59 | % |
The number of retail customers purchasing electric generation andor natural gas from competitive electric generationsuppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:
|
| | | | | | | | | | | |
| September 30, 2017 | | September 30, 2016 |
| Number of Customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 339,300 |
| | 27 | % | | 334,100 |
| | 26 | % |
Natural Gas | 148,600 |
| | 22 | % | | 150,000 |
| | 23 | % |
The changes in BGE’stherefore PECO does not record Operating revenues net of purchasedor Purchased power and fuel expense for the three and nine months ended September 30, 2017, comparedrelated to the same periodelectricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in 2016, consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
| Electric | | Gas | | Total | | Electric | | Gas | | Total |
Distribution rate increase | $ | — |
| | $ | — |
| | $ | — |
| | $ | 21 |
| | $ | 29 |
| | $ | 50 |
|
Regulatory required programs | 2 |
| | — |
| | 2 |
| | 11 |
| | 1 |
| | 12 |
|
Transmission revenue | 7 |
| | — |
| | 7 |
| | 10 |
| | — |
| | 10 |
|
Other, net | 4 |
| | 4 |
| | 8 |
| | 5 |
| | 6 |
| | 11 |
|
Total increase | $ | 13 |
| | $ | 4 |
| | $ | 17 |
| | $ | 47 |
| | $ | 36 |
| | $ | 83 |
|
Distribution Rate Increase. The increase in distributionOperating revenues for the nine months ended September 30, 2017, comparedand Purchased power and fuel expense related to the same period in 2016, was primarily due to the impact of the electric andelectricity, natural gas, distribution rates charged to customers that became effective in June 2016 in accordance with the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016. RECs.
See Note 5 — Regulatory MattersSegment Information of the Combined Notes to Consolidated Financial Statements for additional information.the presentation of PECO's revenue disaggregation.
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and usage conditions. The MDPSC allows BGE to record a monthly adjustment to its electric and natural gas distribution revenue from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service natural gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE's electric and natural gas distribution volumes, thereby recovering a specified dollar amount of distribution revenue per customer, by customer class, regardless of fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges per customer, regardless of what BGE's actual distribution volumes were for a billing period. Therefore, while this revenue is affected by customer growth (i.e., increase in the number of customers), it will not be affected by actual weather or usage conditions (i.e., changes in consumption per customer). BGE bills or credits customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in BGE's service territory. The changes in heating and cooling degree days in BGE's service territory$77 million for the three and nine months ended September 30, 2017March 31, 2023 compared to the same period in 20162022, in Purchased power and fuelexpense is offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | | | | |
| | | Three Months Ended March 31, 2023 |
| | | Increase (Decrease) |
Labor, other benefits, contracting and materials | | | $ | 14 | |
Credit loss expense | | | 10 | |
BSC costs | | | 2 | |
Pension and non-pension postretirement benefit expense | | | (2) | |
Storm-related costs | | | (4) | |
Other | | | (3) | |
| | | 17 | |
Regulatory required programs | | | 6 | |
Total increase | | | $ | 23 | |
|
| | | | | | | | | | | | | | |
Heating and Cooling Degree-Days | | | | | | | % Change |
Three Months Ended September 30, | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 64 |
| | 24 |
| | 78 |
| | 166.7 | % | | (17.9 | )% |
Cooling Degree-Days | 595 |
| | 747 |
| | 596 |
| | (20.3 | )% | | (0.2 | )% |
| | | | | | | | | |
Nine Months Ended September 30, | | | | | | | | | |
Heating Degree-Days | 2,524 |
| | 2,878 |
| | 2,992 |
| | (12.3 | )% | | (15.6 | )% |
Cooling Degree-Days | 877 |
| | 966 |
| | 850 |
| | (9.2 | )% | | 3.2 | % |
Regulatory Required Programs. Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full cost recovery, as well as a returnThe changes in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense consisted of the following:
| | | | | | | | | |
| | | Three Months Ended March 31, 2023 |
| | | Increase (Decrease) |
Depreciation and amortization(a) | | | $ | 7 | |
Regulatory asset amortization | | | (1) | |
| | | |
Total increase | | | $ | 6 | |
__________
(a)Depreciation and Taxes other than income in BGE's Consolidated Statementsamortization increased primarily due to ongoing capital expenditures.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing determinants. The increase in transmission revenuePECO
Interest expense, net increased $7 million for the three and nine months ended September 30, 2017,March 31, 2023, compared to the same period in 2016, was2022, primarily due to the issuance of debt in 2022 and increases in capital investment and operating and maintenance expense recoveries. See Operating and Maintenance Expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.interest rates.
Other, Net. Other net revenue, which can vary from period to period, primarily includes late payment fees and other miscellaneous revenue such as service application fees and assistance provided to other utilities through BGE's mutual assistance program.
Operating and Maintenance Expense
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Increase (Decrease) | | Nine Months Ended September 30, | | Increase (Decrease) |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating and maintenance expense — baseline | $ | 167 |
| | $ | 170 |
| | $ | (3 | ) | | $ | 499 |
| | $ | 561 |
| | $ | (62 | ) |
Operating and maintenance expense — regulatory required programs(a) | 8 |
| | 8 |
| | — |
| | 33 |
| | 27 |
| | 6 |
|
Total operating and maintenance expense | $ | 175 |
| | $ | 178 |
| | $ | (3 | ) | | $ | 532 |
| | $ | 588 |
| | $ | (56 | ) |
_________ | |
(a) | Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues. |
The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Baseline | | | |
Impairment on long-lived assets and losses on regulatory assets(a) | $ | 1 |
| | $ | (50 | ) |
City of Baltimore conduit fees | (4 | ) | | (12 | ) |
Storm-related costs | 3 |
| | (11 | ) |
Uncollectible accounts expense | (8 | ) | | (8 | ) |
BSC costs | 8 |
| | 10 |
|
Other | (3 | ) | | 9 |
|
| (3 | ) | | (62 | ) |
Regulatory Required Programs | | | |
Other | $ | — |
| | $ | 6 |
|
| — |
| | 6 |
|
Total decrease | $ | (3 | ) | | $ | (56 | ) |
__________
| |
(a) | See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. |
Depreciation and Amortization
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Depreciation expense(a) | $ | 5 |
| | $ | 10 |
|
Regulatory asset amortization(b) | 1 |
| | 25 |
|
Regulatory required programs(c) | 2 |
| | 6 |
|
Total increase | $ | 8 |
| | $ | 41 |
|
_________
| |
(a) | Depreciation expense increased due to ongoing capital expenditures. |
| |
(b) | Regulatory asset amortization increased for the three and nine months ended September 30, 2017 compared to the same period in 2016 primarily due to an increase in regulatory asset amortization related to energy efficiency programs and the initiation of cost recovery of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in June 2016 and increased depreciation from AMI program capital expenditures. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(c) | Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues. |
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2017 compared to the same period in 2016 remained relatively consistent.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2017, compared to the same period in 2016 remained relatively consistent.
Effective Income Tax Rate
BGE’s effective income tax rate was 39.2%rates were 2.4% and 39.1%6.4% for the three months ended September 30, 2017March 31, 2023 and 2016, respectively. BGE’s effective income tax rate was 39.5% and 36.3% for the nine months ended September 30, 2017 and 2016,2022, respectively. See Note 127 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
BGE Electric Operating Statistics and Revenue Detail |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Weather - Normal % Change | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change |
Retail Deliveries to Customers (in GWhs) | 2017 |
| 2016 | | | 2017 | | 2016 | |
Retail Deliveries(a) | | | | | | | | | | | | | | | |
Residential | 3,370 |
| | 3,900 |
| | (13.6 | )% | | (2.9 | )% | | 9,126 |
| | 9,996 |
| | (8.7 | )% | | (4.3 | )% |
Small commercial & industrial | 785 |
| | 877 |
| | (10.5 | )% | | (9.0 | )% | | 2,210 |
| | 2,343 |
| | (5.7 | )% | | (5.8 | )% |
Large commercial & industrial | 3,781 |
| | 3,992 |
| | (5.3 | )% | | (3.9 | )% | | 10,422 |
| | 10,627 |
| | (1.9 | )% | | (2.6 | )% |
Public authorities & electric railroads | 64 |
| | 72 |
| | (11.1 | )% | | (2.5 | )% | | 204 |
| | 215 |
| | (5.1 | )% | | (2.5 | )% |
Total electric deliveries | 8,000 |
| | 8,841 |
| | (9.5 | )% | | (4.0 | )% | | 21,962 |
| | 23,181 |
| | (5.3 | )% | | (3.7 | )% |
|
| | | | | |
| As of September 30, |
Number of Electric Customers | 2017 | | 2016 |
Residential | 1,156,659 |
| | 1,145,020 |
|
Small commercial & industrial | 113,224 |
| | 112,609 |
|
Large commercial & industrial | 12,144 |
| | 12,030 |
|
Public authorities & electric railroads | 274 |
| | 282 |
|
Total | 1,282,301 |
| | 1,269,941 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Nine Months Ended September 30, | | % Change |
Electric Revenue | 2017 |
| 2016 | | | 2017 | | 2016 | |
Retail Sales(a) | | | | | | | | | | | |
Residential | $ | 376 |
| | $ | 451 |
| | (16.6 | )% | | $ | 1,096 |
| | $ | 1,203 |
| | (8.9 | )% |
Small commercial & industrial | 67 |
| | 74 |
| | (9.5 | )% | | 202 |
| | 212 |
| | (4.7 | )% |
Large commercial & industrial | 120 |
| | 123 |
| | (2.4 | )% | | 343 |
| | 337 |
| | 1.8 | % |
Public authorities & electric railroads | 8 |
| | 9 |
| | (11.1 | )% | | 23 |
| | 27 |
| | (14.8 | )% |
Total retail | 571 |
|
| 657 |
| | (13.1 | )% | | 1,664 |
|
| 1,779 |
| | (6.5 | )% |
Other revenue(b)(c) | 87 |
| | 78 |
| | 11.5 | % | | 231 |
| | 219 |
| | 5.5 | % |
Total electric revenue | $ | 658 |
|
| $ | 735 |
| | (10.5 | )% | | $ | 1,895 |
|
| $ | 1,998 |
| | (5.2 | )% |
_________
| |
(a) | Reflects delivery volumes and revenue from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission. |
| |
(b) | Other revenue primarily includes wholesale transmission revenue and late payment charges. |
| |
(c) | Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2017 and 2016 and $5 million for both the nine months ended September 30, 2017 and 2016. |
BGE Natural Gas Operating Statistics and Revenue Detail |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Weather - Normal % Change | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change |
Deliveries to Customers (in mmcf) | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Deliveries(a) | | | | | | | | | | | | | | | |
Retail sales | 11,221 |
| | 13,159 |
| | (14.7 | )% | | (14.3 | )% | | 60,620 |
| | 69,415 |
| | (12.7 | )% | | (5.3 | )% |
Transportation and other(b) | 68 |
| | 1,311 |
| | (94.8 | )% | | n/a |
| | 2,463 |
| | 4,078 |
| | (39.6 | )% | | n/a |
|
Total natural gas deliveries | 11,289 |
| | 14,470 |
| | (22.0 | )% | | (14.3 | )% | | 63,083 |
| | 73,493 |
| | (14.2 | )% | | (5.3 | )% |
|
| | | | | |
| As of September 30, |
Number of Gas Customers | 2017 |
| 2016 |
Residential | 626,039 |
| | 619,837 |
|
Commercial & industrial | 43,973 |
| | 43,957 |
|
Total | 670,012 |
|
| 663,794 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Nine Months Ended September 30, | | % Change |
Natural Gas Revenue | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Sales(a) | | | | | | | | | | | |
Retail sales | $ | 77 |
| | $ | 71 |
| | 8.5 | % | | $ | 445 |
| | $ | 403 |
| | 10.4 | % |
Transportation and other(b) | 3 |
| | 6 |
| | (50.0 | )% | | 23 |
| | 20 |
| | 15.0 | % |
Total natural gas revenues(c) | $ | 80 |
| | $ | 77 |
| | 3.9 | % | | $ | 468 |
| | $ | 423 |
| | 10.6 | % |
_________
| |
(a) | Reflects delivery volumes and revenue from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas. |
| |
(b) | Transportation and other natural gas revenue includes off-system revenue of 68 mmcfs ($1 million) and 1,311 mmcfs ($4 million) for the three months ended September 30, 2017 and 2016, respectively, and 2,463 mmcfs ($15 million) and 4,078 mmcfs ($14 million) for the nine months ended September 30, 2017 and 2016, respectively. |
| |
(c) | Includes operating revenues from affiliates totaling $2 million and $6 million for the three months ended September 30, 2017 and 2016, respectively, and $7 million and $11 million for the nine months ended September 30, 2017 and 2016, respectively. |
Results of Operations — PHIBGE
PHI’s results | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, | | Favorable (Unfavorable) Variance |
| | | | | | 2023 | | 2022 | |
Operating revenues | | | | | | | $ | 1,257 | | | $ | 1,154 | | | $ | 103 | |
Operating expenses | | | | | | | | | | | |
Purchased power and fuel | | | | | | | 492 | | | 454 | | | (38) | |
Operating and maintenance | | | | | | | 222 | | | 218 | | | (4) | |
Depreciation and amortization | | | | | | | 167 | | | 171 | | | 4 | |
Taxes other than income taxes | | | | | | | 83 | | | 76 | | | (7) | |
Total operating expenses | | | | | | | 964 | | | 919 | | | (45) | |
| | | | | | | | | | | |
Operating income | | | | | | | 293 | | | 235 | | | 58 | |
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | | | | | | | (44) | | | (35) | | | (9) | |
Other, net | | | | | | | 3 | | | 7 | | | (4) | |
Total other income and (deductions) | | | | | | | (41) | | | (28) | | | (13) | |
Income before income taxes | | | | | | | 252 | | | 207 | | | 45 | |
Income taxes | | | | | | | 52 | | | 9 | | | (43) | |
Net income | | | | | | | $ | 200 | | | $ | 198 | | | $ | 2 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. Net income increased $2 million primarily due to a favorable impacts of operations include the resultsmulti-year plans, partially offset by an increase in interest expense. See Note 3 — Regulatory Matters of itsthe Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.
The changes in Operating revenues consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, 2023 |
| | | Increase |
| | | | | | | Electric | | Gas | | Total |
Distribution | | | | | | | $ | 26 | | | $ | 23 | | | $ | 49 | |
Transmission | | | | | | | 18 | | | — | | | 18 | |
Other | | | | | | | — | | | 1 | | | 1 | |
| | | | | | | 44 | | | 24 | | | 68 | |
Regulatory required programs | | | | | | | 34 | | | 1 | | | 35 | |
Total increase | | | | | | | $ | 78 | | | $ | 25 | | | $ | 103 | |
Revenue Decoupling.The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a monthly rate adjustment that provides for fixed distribution revenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
| | | | | | | | | | | |
| As of March 31, |
Number of Electric Customers | 2023 | | 2022 |
Residential | 1,207,486 | | | 1,199,272 | |
Small commercial & industrial | 115,658 | | | 115,363 | |
Large commercial & industrial | 12,911 | | | 12,674 | |
Public authorities & electric railroads | 266 | | | 268 | |
Total | 1,336,321 | | | 1,327,577 | |
| | | | | | | | | | | |
| As of March 31, |
Number of Natural Gas Customers | 2023 | | 2022 |
Residential | 656,583 | | | 653,397 | |
Small commercial & industrial | 38,260 | | | 38,356 | |
Large commercial & industrial | 6,261 | | | 6,193 | |
| | | |
Total | 701,104 | | | 697,946 | |
Distribution Revenue increased for the three reportable segments, Pepco, DPLmonths ended March 31, 2023,compared to the same period in 2022, due to favorable impacts of the multi-year plans.
Transmission Revenue.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and ACEcapital investments being recovered. Transmission revenue increased for the three months ended March 31, 2023, compared to the same period in 2022, primarily due to increases in underlying costs and capital investments.
Other Revenue includes revenue related to late payment, charges, mutual assistance, off-system sales, and service application fees.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all periods presented below.customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For "Predecessor" reporting periods, PHI's results of operations also includecustomers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the results of PESbilling agent and PCI. therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.
See Note 20 -5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding PHI's reportable segments. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussionthe presentation of the results of operations for Pepco, DPL and ACE is presented elsewhere in this report.BGE's revenue disaggregation.
As a result of the PHI Merger, the following consolidated financial results present two separate reporting periods for 2016. The "Predecessor" reporting period represents PHI's results of operations for the period from January 1, 2016 to March 23, 2016. The "Successor" reporting periods represent PHI's results of operations for the three and nine months ended September 30, 2017, the three months ended September 30, 2016 and for the period from March 24, 2016 to September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | | Successor | | | Predecessor |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | March 24 to September 30, | | | January 1 to March 23, |
| 2017 | | 2016 | | | 2017 | | 2016 | | | 2016 |
Operating revenues | $ | 1,310 |
| | $ | 1,394 |
| | $ | (84 | ) | | $ | 3,557 |
| | $ | 2,565 |
| | | $ | 1,153 |
|
Purchased power and fuel expense | 473 |
| | 583 |
| | 110 |
| | 1,318 |
| | 1,037 |
| | | 497 |
|
Revenue net of purchased power and fuel expense(a) | 837 |
| | 811 |
| | 26 |
| | 2,239 |
| | 1,528 |
| | | 656 |
|
Other operating expenses | | | | | | | | | | | | |
Operating and maintenance | 251 |
| | 226 |
| | (25 | ) | | 774 |
| | 921 |
| | | 294 |
|
Depreciation and amortization | 179 |
| | 182 |
| | 3 |
| | 511 |
| | 355 |
| | | 152 |
|
Taxes other than income | 122 |
| | 124 |
| | 2 |
| | 344 |
| | 248 |
| | | 105 |
|
Total other operating expenses | 552 |
| | 532 |
| | (20 | ) | | 1,629 |
| | 1,524 |
| | | 551 |
|
Gain on sales of assets | — |
| | — |
| | — |
| | 1 |
| | — |
| | | — |
|
Operating income | 285 |
| | 279 |
| | 6 |
| | 611 |
| | 4 |
| | | 105 |
|
Other income and (deductions) | | | | | | | | | | | | |
Interest expense, net | (62 | ) | | (64 | ) | | 2 |
| | (183 | ) | | (135 | ) | | | (65 | ) |
Other, net | 13 |
| | 19 |
| | (6 | ) | | 40 |
| | 31 |
| | | (4 | ) |
Total other income and (deductions) | (49 | ) | | (45 | ) | | (4 | ) | | (143 | ) | | (104 | ) | | | (69 | ) |
Income (loss) before income taxes | 236 |
| | 234 |
| | 2 |
| | 468 |
| | (100 | ) | | | 36 |
|
Income taxes | 83 |
| | 68 |
| | (15 | ) | | 109 |
| | (9 | ) | | | 17 |
|
Net income (loss) | $ | 153 |
| | $ | 166 |
| | $ | (13 | ) | | $ | 359 |
| | $ | (91 | ) | | | $ | 19 |
|
_________
| |
(a) | PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
Successor Period Three Months Ended September 30, 2017 Compared to Successor Period Three Months Ended September 30, 2016
Net Income
PHI's Net income for the Successor period of three months ended September 30, 2017 was $153 million compared to $166 million for the Successor period of three months ended September 30, 2016. The decrease in Net income reflects the September 2016 pre-tax recording of a $50 million reallocation of merger-related commitments from Pepco, DPL and ACE to Exelon, which resulted in more commitments becoming obligations of Exelon. The increase in Operating
and maintenance expense is partially offset by the impact of increases in electric distribution and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 in New Jersey).
Operating Revenue Net of Purchased Power and Fuel Expense
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $26$38 million for the three months ended September 30, 2017 asMarch 31, 2023 compared to the three months ended September 30, 2016. same period in 2022, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The increase is primarily attributable to the following factors:
Increase of $17 million at DPL primarily related to the impact of the new electric distribution and natural gas rates charged to Delaware customers that became effectivechanges in July 2016 and December 2016 and the impact of new electric distribution rates charged to Maryland customers that became effective in February 2017;
Increase of $14 million at Pepco primarily related to the impact of the new electric distribution rates charged to customers in Maryland that became effective in November 2016 and and the impact of new electric distribution rates charged to customers in the District of Columbia effective August 2017; and
Decrease of $6 million at ACE primarily related to lower average customer usage and unfavorable weather related sales, partially offset by the impact of the new electric distribution base rate charged to customers that became effective in August 2016.
Operating and Maintenance Expense
Operating and maintenance expense consisted of the following:
| | | | | | | | | |
| | | Three Months Ended March 31, 2023 |
| | | Increase (Decrease) |
Labor, other benefits, contracting, and materials | | | $ | 8 | |
Storm-related costs | | | (5) | |
Pension and non-pension postretirement benefits expense | | | 1 | |
BSC costs | | | 3 | |
| | | |
| | | |
Other | | | (3) | |
| | | 4 | |
Regulatory required programs | | | — | |
| | | |
Total increase | | | $ | 4 | |
| | | |
| | | |
| | | |
The changes in Depreciation and amortization expense consisted of the following:
| | | | | | | | | |
| | | Three Months Ended March 31, 2023 |
| | | Increase (Decrease) |
Depreciation and amortization(a) | | | $ | 7 | |
Regulatory required programs | | | (9) | |
Regulatory asset amortization | | | (2) | |
| | | |
Total decrease | | | $ | (4) | |
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net increased by $25$9 million for the three months ended September 30, 2017 asMarch 31, 2023, compared to the three months ended September 30, 2016. The increase is attributable to the following factors:
Increase of $24 million at DPL due primarily to a merger commitment reallocation from DPL to Exelon that decreased Operating and maintenance expensesame period in 2016;
Increase of $5 million at ACE2022, primarily due to a merger commitment reallocation from ACE to Exelon that decreased Operatingan increase in interest rates and maintenance expense in 2016, partially offset by the deferralissuance of merger-related costs to a regulatory asset; and
Decrease of $6 million at Pepco primarily due to the deferral of merger-related, rate case, and customer billing system costs to a regulatory asset, partially offset by a merger commitment reallocation from Pepco to Exelon that decreased Operating and maintenance expense in 2016.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased by $3 million primarily due to lower amortization expense at ACE resulting from lower revenue due to rate decreases effective October 2016 for the ACE Transition Bond Charge and ACE Market Transition Charge Tax, partially offset by higher depreciation as a result of higher Maryland depreciation rates at Pepco effective November 2016 and at DPL effective February 2017 and due to ongoing capital expenditures at Pepco, DPL, and ACE.
Taxes Other Than Income
Taxes other than income decreased by $2 million primarily due to lower utility taxes that are collected and passed through by Pepco, partially offset by higher property taxes at Pepco.
Interest Expense, Net
Interest expense decreased by $2 million primarily due to the redemption of long-term debt in December 2016 and lower short-term debt interest rates.Q2 2022.
Other, Net
Other, net decreased by $6 million primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.
Effective Income Tax Rate
PHI's effective income tax rate was 35.2%rateswere 20.6% and 29.1%4.3% for the three months ended September 30, 2017March 31, 2023 and 2016,2022, respectively. The change is primarily due to a decrease in the multi-year plans' accelerated income tax benefits in 2023 as compared to 2022. See Note 12 -3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans and Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations — PHI
PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three months ended March 31, 2023 compared to the same period in 2022. See the Results of Operations for Pepco, DPL, and ACE for additional information.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Favorable (Unfavorable) Variance | | | | |
| 2023 | | 2022 | | | | | | |
PHI | $ | 155 | | | $ | 130 | | | $ | 25 | | | | | | | |
Pepco | 65 | | | 46 | | | 19 | | | | | | | |
DPL | 60 | | | 56 | | | 4 | | | | | | | |
ACE | 33 | | | 26 | | | 7 | | | | | | | |
Other(a) | (3) | | | 2 | | | (5) | | | | | | | |
__________
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investment activities.
Three Months Ended September 30, 2017
PHI's March 31, 2023 Compared to Three Months Ended March 31, 2022. Net income for the Successor periodIncome increased by $25 millionprimarily due to favorable impacts as a result of nine months ended September 30, 2017 was $359 million. Therewere no significant changes in the underlying trends affecting PHI's operations during the Successor periodPepco Maryland and DPL Maryland multi-year plans, timing of nine months ended September 30, 2017 except for the impact of increases in electric distribution and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017decoupling revenues in the District of Columbia, DPL electrichigher distribution rates effective February 2017at DPL Delaware, and higher transmission rates at Pepco and ACE, partially offset by an increase in Maryland,environmental liabilities at Pepco, and unfavorable weather conditions at DPL Delaware electric distribution and natural gas service territories.
Results of Operations — Pepco
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Favorable (Unfavorable) Variance | | | | |
2023 | | 2022 | | | | | | |
Operating revenues | $ | 710 | | | $ | 614 | | | $ | 96 | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Operating expenses | | | | | | | | | | | |
Purchased power | 258 | | | 213 | | | (45) | | | | | | | |
Operating and maintenance | 150 | | | 131 | | | (19) | | | | | | | |
Depreciation and amortization | 108 | | | 108 | | | — | | | | | | | |
Taxes other than income taxes | 94 | | | 95 | | | 1 | | | | | | | |
Total operating expenses | 610 | | | 547 | | | (63) | | | | | | | |
| | | | | | | | | | | |
Operating income | 100 | | | 67 | | | 33 | | | | | | | |
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | (39) | | | (36) | | | (3) | | | | | | | |
Other, net | 16 | | | 13 | | | 3 | | | | | | | |
Total other income and (deductions) | (23) | | | (23) | | | — | | | | | | | |
Income before income taxes | 77 | | | 44 | | | 33 | | | | | | | |
Income taxes | 12 | | | (2) | | | (14) | | | | | | | |
Net income | $ | 65 | | | $ | 46 | | | $ | 19 | | | | | | | |
Three Months Ended March 31, 2023Compared to Three Months Ended March 31, 2022. Net Income increased by$19 million primarily due to favorable impacts of the Maryland multi-year plan, timing of decoupling revenues in the District of Columbia, and higher transmission rates, effective July 2016partially offset by an increase in environmental liabilities.
The changes in Operating revenues consisted of the following:
| | | | | | | |
| Three Months Ended March 31, 2023 | | |
| Increase | | |
Distribution | $ | 40 | | | |
Transmission | 18 | | | |
| | | |
| 58 | | | |
Regulatory required programs | 38 | | | |
Total increase | $ | 96 | | | |
Revenue Decoupling. The demand for electricity is affected by weather and December 2016 in Delaware, and ACEcustomer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
| | | | | | | | | | | |
| As of March 31, |
Number of Electric Customers | 2023 | | 2022 |
Residential | 859,207 | | | 846,258 | |
Small commercial & industrial | 54,089 | | | 54,509 | |
Large commercial & industrial | 22,858 | | | 22,620 | |
Public authorities & electric railroads | 201 | | | 184 | |
Total | 936,355 | | | 923,571 | |
Distribution Revenue increased for the three months ended March 31, 2023 compared to the same period in 2022 primarily due to favorable impacts of the Maryland multi-year plan and higher rates effective August 2016due to the expiration of customer offsets and timing of decoupling revenues in New Jersey).the District of Columbia.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2023, compared to the same period in 2022, primarily due to increases in capital investment and underlying costs.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The deferralriders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of merger-related, rate case, and customer billing system costs to a regulatory asset and lower uncollectible accountsthese programs are included in Purchased power expense, contributed to lower Operating and maintenance expense. Income taxes were lower dueexpense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to unrecognized tax benefitspurchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of $59 milliondeliveries, as Pepco remains the distribution service provider for uncertain tax positionsall customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the deductibilityelectricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.
See Note 5 — Segment Information of certain merger commitmentsthe Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $45 million for the three months ended March 31, 2023 compared to the same period in 2022, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the first quarterfollowing:
| | | | | | | |
| Three Months Ended March 31, 2023 | | |
| Increase (Decrease) | | |
Labor, other benefits, contracting and materials(a) | $ | 24 | | | |
Pension and non-pension postretirement benefits expense | 3 | | | |
| | | |
| | | |
Storm-related costs | (5) | | | |
Credit loss expense | (4) | | | |
BSC and PHISCO Costs | (1) | | | |
Other | (3) | | | |
| 14 | | | |
| | | |
Regulatory required programs | 5 | | | |
Total increase | $ | 19 | | | |
__________(a)Primarily reflects an increase in environmental liabilities.
The changes in Depreciation and amortization expense consisted of the following:
| | | | | | | |
| Three Months Ended March 31, 2023 | | |
| Increase (Decrease) | | |
Depreciation and amortization(a) | $ | 3 | | | |
Regulatory asset amortization | 4 | | | |
Regulatory required programs | (7) | | | |
Total increase | $ | — | | | |
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax raterates were 15.6% and (4.5)% for the Successor period of ninethree months ended September 30, 2017 was 23.3%.March 31, 2023 and 2022, respectively. See Note 12 -7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Successor Period March 24, 2016 to September 30, 2016
PHI's Net loss for the Successor period from March 24, 2016 to September 30, 2016was $91 million. Therewere no significant changes in the underlying trends affecting PHI's results of operations during the Successor period of March 24, 2016 to September 30, 2016 except for the pre-tax recording of $375 million of non-recurring merger-related costs within Operating and maintenance expense.
PHI's effective income tax rate for the Successor period of March 24, 2016 to September 30, 2016 was 9.0%. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Predecessor Period January 1, 2016 to March 23, 2016
PHI's Net income for the Predecessor period of January 1, 2016 to March 23, 2016was $19 million. Therewere no significant changes in the underlying trends affecting PHI's results of operations during the Predecessor period of January 1, 2016 to March 23, 2016 except for the pre-tax recording of $29 million of non-recurring merger-related costs within Operating and maintenance expense and $18 million of preferred stock derivative expense within Other, net.
PHI's effective income tax rate for the Predecessor period of January 1, 2016 to March 23, 2016 was 47.2%. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations - Pepco— DPL
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Favorable (Unfavorable) Variance | | | | |
2023 | | 2022 | | | | | | |
Operating revenues | $ | 474 | | | $ | 431 | | | $ | 43 | | | | | | | |
Operating expenses | | | | | | | | | | | |
Purchased power and fuel | 221 | | | 189 | | | (32) | | | | | | | |
Operating and maintenance | 87 | | | 93 | | | 6 | | | | | | | |
Depreciation and amortization | 60 | | | 57 | | | (3) | | | | | | | |
Taxes other than income taxes | 20 | | | 18 | | | (2) | | | | | | | |
Total operating expenses | 388 | | | 357 | | | (31) | | | | | | | |
| | | | | | | | | | | |
Operating income | 86 | | | 74 | | | 12 | | | | | | | |
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | (17) | | | (16) | | | (1) | | | | | | | |
Other, net | 3 | | | 2 | | | 1 | | | | | | | |
Total other income and (deductions) | (14) | | | (14) | | | — | | | | | | | |
Income before income taxes | 72 | | | 60 | | | 12 | | | | | | | |
Income taxes | 12 | | | 4 | | | (8) | | | | | | | |
Net income | $ | 60 | | | $ | 56 | | | $ | 4 | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
2017 | | 2016 | | | 2017 | | 2016 | |
Operating revenues | $ | 604 |
| | $ | 635 |
| | $ | (31 | ) | | $ | 1,649 |
| | $ | 1,695 |
| | $ | (46 | ) |
Purchased power expense | 168 |
| | 213 |
| | 45 |
| | 478 |
| | 563 |
| | 85 |
|
Revenue net of purchased power expense(a) | 436 |
| | 422 |
| | 14 |
| | 1,171 |
| | 1,132 |
| | 39 |
|
Other operating expenses | | | | | | | | | | | |
Operating and maintenance | 103 |
| | 109 |
| | 6 |
| | 336 |
| | 508 |
| | 172 |
|
Depreciation and amortization | 82 |
| | 76 |
| | (6 | ) | | 242 |
| | 221 |
| | (21 | ) |
Taxes other than income | 102 |
| | 105 |
| | 3 |
| | 282 |
| | 287 |
| | 5 |
|
Total other operating expenses | 287 |
| | 290 |
| | 3 |
| | 860 |
| | 1,016 |
| | 156 |
|
Gain on sales of assets | — |
| | — |
| | — |
| | 1 |
| | 8 |
| | (7 | ) |
Operating income | 149 |
| | 132 |
| | 17 |
| | 312 |
| | 124 |
| | 188 |
|
Other income and (deductions) | | | | |
| | | | | |
|
Interest expense, net | (31 | ) | | (30 | ) | | (1 | ) | | (89 | ) | | (98 | ) | | 9 |
|
Other, net | 7 |
| | 12 |
| | (5 | ) | | 22 |
| | 28 |
| | (6 | ) |
Total other income and (deductions) | (24 | ) | | (18 | ) | | (6 | ) | | (67 | ) | | (70 | ) | | 3 |
|
Income before income taxes | 125 |
| | 114 |
| | 11 |
| | 245 |
| | 54 |
| | 191 |
|
Income taxes | 38 |
| | 35 |
| | (3 | ) | | 57 |
| | 34 |
| | (23 | ) |
Net income | $ | 87 |
| | $ | 79 |
| | $ | 8 |
| | $ | 188 |
| | $ | 20 |
| | $ | 168 |
|
_________
| |
(a) | Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Pepco has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
Net Income
Three Months Ended September 30, 2017March 31, 2023 Compared to Three Months Ended September 30, 2016. Pepco's March 31, 2022. Net income for the three months ended September 30, 2017, was higher than the same period in 2016,increased $4 million primarily due to an increasefavorable impacts of the Maryland multi-year plan, higher Delaware electric and natural gas distribution rates, partially offset by unfavorable weather conditions at Delaware electric and natural gas service territories.
The changes in Operating revenues consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2023 | | |
| (Decrease) Increase | | |
| Electric | | Gas | | Total | | | | | | |
Weather | $ | (5) | | | $ | (4) | | | $ | (9) | | | | | | | |
Volume | (2) | | | (2) | | | (4) | | | | | | | |
Distribution | 11 | | | 5 | | | 16 | | | | | | | |
Transmission | 7 | | | — | | | 7 | | | | | | | |
| | | | | | | | | | | |
| 11 | | | (1) | | | 10 | | | | | | | |
Regulatory required programs | 18 | | | 15 | | | 33 | | | | | | | |
Total increase | $ | 29 | | | $ | 14 | | | $ | 43 | | | | | | | |
Revenue net of purchased power expense resultingDecoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from higher electric distribution revenuesin Maryland are not impacted by abnormal weather or usage per customer as a result of the distribution rate increase approved by the MDPSC effective November 2016 and the distribution rate increase approved by the DCPSC effective August 2017.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Pepco's Net income for the nine months ended September 30, 2017, was higher than the same period in 2016, primarily due to an increase in Revenue net of purchased power expense resulting from higher electric distribution revenues as a result of the distribution rate increase approved by the MDPSC effective November 2016 and the distribution rate increase approved by the DCPSC effective August 2017, lower Operating and maintenance expense due to merger-related costs recognized in March 2016, and a decrease in income tax reserves in the first quarter of 2017 for uncertain tax positions related to the deductibility of certain merger commitments, partially offset by higher depreciation expense due to increased depreciation rates in Maryland effective November 2016.
Operating Revenue Net of Purchased Power Expense
Operating revenues include revenue from the distribution and supply of electricity to Pepco’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All Pepco customers have the choice to purchase electricity from competitive electric generation
suppliers. The customers' choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2017, compared to the same periods in 2016, consisted of the following:
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Electric | 65 | % | | 63 | % | | 66 | % | | 65 | % |
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:
|
| | | | | | | | | | | |
| September 30, 2017 | | September 30, 2016 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 179,106 |
| | 21 | % | | 175,960 |
| | 21 | % |
Retail deliveries purchased from competitive electric generation suppliers represented 72% and 73% of Pepco’s retail kWh sales to the District of Columbia customers and 60% and 60% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 71% and 72% of Pepco’s retail kWh sales to the District of Columbia customers and 58% and 59% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.
Operating revenues include transmission enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Purchased power expense consists of the cost of electricity purchased by Pepco to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.
The changes in Pepco’s operating revenues net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Volume | $ | 5 |
| | $ | 13 |
|
Distribution rate increase | 17 |
| | 45 |
|
Regulatory required programs | (6 | ) | | (11 | ) |
Transmission revenues | 3 |
| | 9 |
|
Other | (5 | ) | | (17 | ) |
Total increase | $ | 14 |
| | $ | 39 |
|
Volume. The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2017 compared to the same periods in 2016, primarily reflects the impact of customer growth.
Distribution Rate Increase. The increase in electric operating revenues net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 was primarily due to the
impact of higher electric distribution rates charged to customers in Maryland that became effective in November 2016 and higher electric distribution rates charged to customers in the District of Columbia that became effective August 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Revenue Decoupling. Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implementedBSA that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling thecustomer by customer class. While Operating revenues from electric distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia to fluctuate from period to period are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customerscustomers.
Weather. The demand for electricity and changesnatural gas in Delaware is affected by weather conditions. With respect to the approved distribution charge per customer. Changeselectric business, very warm weather in customer usage (duesummer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended March 31, 2023 compared to the same period in 2022, Operating revenues related to weather decreased due to unfavorable weather conditions energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.in Delaware electric and natural gas service territories.
In accounting for the BSA in Maryland and the District
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in Pepco'sthe Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in Pepco’sthe Delaware service territory for the three and nine months ended September 30, 2017March 31, 2023 compared to the same periodsperiod in 20162022 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Three Months Ended March 31, | | | | % Change |
Delaware Electric Service Territory | 2023 | | 2022 | | Normal | | 2023 vs. 2022 | | 2023 vs. Normal |
Heating Degree-Days | 1,952 | | | 2,355 | | | 2,489 | | | (17.1) | % | | (21.6) | % |
Cooling Degree-Days | — | | | 3 | | | 1 | | | (100.0) | % | | (100.0) | % |
|
| | | | | | | | | | | | | | |
| | | | | % Change |
| 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Three Months Ended September 30, | | | | | | | | | |
Heating Degree-Days | 8 |
| | 1 |
| | 19 |
| | 700.0 | % | | (57.9 | )% |
Cooling Degree-Days | 1,130 |
| | 1,418 |
| | 1,133 |
| | (20.3 | )% | | (0.3 | )% |
| | | | | | |
|
| |
|
|
Nine Months Ended September 30, | | | | | | |
|
| |
|
|
Heating Degree-Days | 1,963 |
| | 2,408 |
| | 2,477 |
| | (18.5 | )% | | (20.8 | )% |
Cooling Degree-Days | 1,679 |
| | 1,872 |
| | 1,611 |
| | (10.3 | )% | | 4.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Three Months Ended March 31, | | | | % Change |
Delaware Natural Gas Service Territory | 2023 | | 2022 | | Normal | | 2023 vs. 2022 | | 2023 vs. Normal |
Heating Degree-Days | 1,952 | | | 2,355 | | | 2,497 | | | (17.1) | % | | (21.8) | % |
Regulatory Required Programs.This representsVolume, exclusive of the effects of weather, decreased for the three months ended March 31, 2023 compared to the same period in 2022 primarily due to customer usage, partially offset by customer growth.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Electric Retail Deliveries to Delaware Customers (in GWhs) | | | | | | | Three Months Ended March 31, | | % Change | | Weather - Normal % Change(b) |
| | | | | | 2023 | | 2022 | | |
Residential | | | | | | | | | 797 | | | 895 | | | (10.9) | % | | (1.2) | % |
Small commercial & industrial | | | | | | | | | 327 | | | 370 | | | (11.6) | % | | (7.2) | % |
Large commercial & industrial | | | | | | | | | 719 | | | 765 | | | (6.0) | % | | (4.7) | % |
Public authorities & electric railroads | | | | | | | | | 9 | | | 9 | | | — | % | | (6.3) | % |
Total electric retail deliveries(a) | | | | | | | | | 1,852 | | | 2,039 | | | (9.2) | % | | (3.6) | % |
| | | | | | | | | | | |
| As of March 31, |
Number of Total Electric Customers (Maryland and Delaware) | 2023 | | 2022 |
Residential | 482,979 | | | 478,009 | |
Small commercial & industrial | 63,794 | | | 63,296 | |
Large commercial & industrial | 1,236 | | | 1,221 | |
Public authorities & electric railroads | 595 | | | 603 | |
Total | 548,604 | | | 543,129 | |
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in operating revenues collected under approved riders to recover costs incurreddelivery volumes assuming normalized weather based on the historical 20-year average.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural Gas Retail Deliveries to Delaware Customers (in mmcf) | | | | | | | Three Months Ended March 31, | | % Change | | Weather - Normal % Change(b) |
| | | | | | 2023 | | 2022 | | |
Residential | | | | | | | | | 3,581 | | | 4,453 | | | (19.6) | % | | (6.6) | % |
Small commercial & industrial | | | | | | | | | 1,652 | | | 1,983 | | | (16.7) | % | | (1.8) | % |
Large commercial & industrial | | | | | | | | | 414 | | | 457 | | | (9.4) | % | | (9.5) | % |
Transportation | | | | | | | | | 1,900 | | | 2,207 | | | (13.9) | % | | (6.9) | % |
Total natural gas deliveries(a) | | | | | | | | | 7,547 | | | 9,100 | | | (17.1) | % | | (5.8) | % |
| | | | | | | | | | | |
| As of March 31, |
Number of Delaware Natural Gas Customers | 2023 | | 2022 |
Residential | 129,791 | | | 128,695 | |
Small commercial & industrial | 10,158 | | | 10,097 | |
Large commercial & industrial | 16 | | | 17 | |
Transportation | 158 | | | 159 | |
Total | 140,123 | | | 138,968 | |
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Distribution Revenue increased for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in Pepco's Consolidated Statements of Operations and Comprehensive Income. Referthe three months ended March 31, 2023 compared to the Operatingsame period in2022 primarily due to favorable impacts of the Maryland multi-year plan that became effective in January 2023, higher natural gas distribution rates effective in August 2022, and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.higher DSIC rates in Delaware that became effective in January 2023.
Transmission Revenues. Revenue.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense forrecovered. During the three months ended September 30, 2017March 31, 2023 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 related to increases in2022, transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.
Other. The decrease in other operating revenue net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 isincreased, primarily due to lower pass-through revenue (which is substantially offset in Taxes other than income) primarily the result of lower sales that resulted in a decrease in utility taxes that are collected by Pepco on behalf of the jurisdiction.increases underlying costs.
Operating and Maintenance Expense
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Increase (Decrease) | | Nine Months Ended September 30, | | Increase (Decrease) |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating and maintenance expense - baseline | $ | 100 |
| | $ | 106 |
| | $ | (6 | ) | | $ | 331 |
| | $ | 500 |
| | $ | (169 | ) |
Operating and maintenance expense - regulatory required programs(a) | 3 |
| | 3 |
| | — |
| | 5 |
| | 8 |
| | (3 | ) |
Total operating and maintenance expense | $ | 103 |
| | $ | 109 |
| | $ | (6 | ) | | $ | 336 |
| | $ | 508 |
| | $ | (172 | ) |
_________
| |
(a) | Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues. |
The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Baseline | | | |
Labor, other benefits, contracting and materials | $ | 2 |
| | $ | 14 |
|
Storm-related costs | (1 | ) | | — |
|
Remeasurement of AMI-related regulatory asset(a) | (4 | ) | | (11 | ) |
Uncollectible accounts expense | 1 |
| | (1 | ) |
Deferral of merger-related costs to regulatory asset | (8 | ) | | (1 | ) |
Deferral of rate case and customer billing system costs | (6 | ) | | (6 | ) |
BSC and PHISCO allocations(b) | 1 |
| | (22 | ) |
Merger commitments(c) | 13 |
| | (132 | ) |
Other | (4 | ) | | (10 | ) |
| (6 | ) | | (169 | ) |
Regulatory required programs | | | |
Purchased power administrative costs | — |
| | (3 | ) |
Total decrease | $ | (6 | ) | | $ | (172 | ) |
_________
| |
(a) | Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016. |
| |
(b) | Primarily related to merger severance and compensation costs recognized in 2016. |
| |
(c) | Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. |
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Depreciation expense(a) | $ | 9 |
| | $ | 25 |
|
Regulatory asset amortization | 3 |
| | 4 |
|
Regulatory required programs(b) | (6 | ) | | (8 | ) |
Total increase | $ | 6 |
| | $ | 21 |
|
_________
| |
(a) | Depreciation expense increased due to higher depreciation rates in Maryland effective November 2016 and due to ongoing capital expenditures. |
| |
(b) | Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense. |
Taxes Other Than Income
Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016, decreased due to a decrease in the utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues), partially offset by higher property taxes.
Gain on sales of assets
Gain on sales of assets for the nine months ended September 30, 2017 compared to the same period in 2016 decreased due to a second quarter 2016 gain recorded from the sale of land.
Interest Expense, Net
Interest expense, net for the three months ended September 30, 2017 compared to the same period in 2016, remained relatively constant.
Interest expense, net for the nine months ended September 30, 2017 compared to the same period in 2016 decreased primarily due to the recording of interest expense for an uncertain tax position in the first quarter of 2016 and an increase in capitalized AFUDC interest.
Other, Net
Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 decreased primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.
Effective Income Tax Rate
Pepco's effective income tax rate was 30.4% and 30.7% for the three months ended September 30, 2017 and 2016, respectively. Pepco's effective income tax rate was 23.3% and 63.0% for the nine months ended September 30, 2017 and 2016, respectively. In the first quarter of 2017, Pepco decreased its liability for unrecognized tax benefits by $21 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Pepco Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | | | Nine Months Ended September 30, | | | | |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | % Change | | Weather - Normal % Change | | 2017 | | 2016 | | % Change | | Weather - Normal % Change |
Retail Deliveries(a) | | | | | | | | | | | | | | | |
Residential | 2,281 |
| | 2,675 |
| | (14.7 | )% | | (5.2 | )% | | 6,038 |
| | 6,652 |
| | (9.2 | )% | | (2.7 | )% |
Small commercial & industrial | 347 |
| | 394 |
| | (11.9 | )% | | (7.2 | )% | | 999 |
| | 1,124 |
| | (11.1 | )% | | (8.4 | )% |
Large commercial & industrial | 4,146 |
|
| 4,314 |
| | (3.9 | )% | | 0.8 | % | | 11,306 |
| | 11,890 |
| | (4.9 | )% | | (3.0 | )% |
Public authorities & electric railroads | 180 |
| | 180 |
| | — | % | | 1.1 | % | | 542 |
| | 544 |
| | (0.4 | )% | | (0.2 | )% |
Total retail deliveries | 6,954 |
| | 7,563 |
| | (8.1 | )% | | (1.7 | )% | | 18,885 |
| | 20,210 |
| | (6.6 | )% | | (3.1 | )% |
|
| | | | | |
| As of September 30, |
Number of Electric Customers | 2017 | | 2016 |
Residential | 790,032 |
| | 775,911 |
|
Small commercial & industrial
| 53,543 |
| | 53,425 |
|
Large commercial & industrial | 21,733 |
| | 21,315 |
|
Public authorities & electric railroads | 143 |
| | 129 |
|
Total | 865,451 |
| | 850,780 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | Nine Months Ended September 30, | | |
Electric Revenue | 2017 | | 2016 | | % Change | | 2017 | | 2016 | | % Change |
Retail Sales(a) | | | | | | | | | | | |
Residential | $ | 283 |
| | $ | 315 |
| | (10.2 | )% | | $ | 744 |
| | $ | 791 |
| | (5.9 | )% |
Small commercial & industrial | 38 |
| | 43 |
| | (11.6 | )% | | 113 |
| | 116 |
| | (2.6 | )% |
Large commercial & industrial | 221 |
| | 219 |
| | 0.9 | % | | 608 |
| | 613 |
| | (0.8 | )% |
Public authorities & electric railroads | 8 |
| | 7 |
| | 14.3 | % | | 24 |
| | 23 |
| | 4.3 | % |
Total retail | 550 |
| | 584 |
| | (5.8 | )% | | 1,489 |
| | 1,543 |
| | (3.5 | )% |
Other revenue(b) | 54 |
| | 51 |
| | 5.9 | % | | 160 |
| | 152 |
| | 5.3 | % |
Total electric revenue(c) | $ | 604 |
| | $ | 635 |
| | (4.9 | )% | | $ | 1,649 |
| | $ | 1,695 |
| | (2.7 | )% |
_________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenue also reflects the cost of energy and transmission. |
| |
(b) | Other revenue includes transmission revenue from PJM and wholesale electric revenues. |
| |
(c) | Includes operating revenues from affiliates totaling $1 million for the three months ended September 30, 2017 and 2016 and $4 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively. |
Results of Operations - DPL
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
2017 | | 2016 | | | 2017 | | 2016 | |
Operating revenues | $ | 327 |
| | $ | 331 |
| | $ | (4 | ) | | $ | 971 |
| | $ | 974 |
| | $ | (3 | ) |
Purchased power and fuel expense | 129 |
| | 150 |
| | 21 |
| | 399 |
| | 448 |
| | 49 |
|
Revenues net of purchased power and fuel expense(a) | 198 |
| | 181 |
| | 17 |
| | 572 |
| | 526 |
| | 46 |
|
Other operating expenses |
|
| |
|
| | | |
|
| |
|
| | |
Operating and maintenance | 79 |
| | 55 |
| | (24 | ) | | 227 |
| | 338 |
| | 111 |
|
Depreciation and amortization | 45 |
| | 44 |
| | (1 | ) | | 124 |
| | 120 |
| | (4 | ) |
Taxes other than income | 15 |
| | 14 |
| | (1 | ) | | 43 |
| | 42 |
| | (1 | ) |
Total other operating expenses | 139 |
| | 113 |
| | (26 | ) | | 394 |
| | 500 |
| | 106 |
|
Gain on sales of asset | — |
| | 4 |
| | (4 | ) | | — |
| | 4 |
| | (4 | ) |
Operating income | 59 |
| | 72 |
| | (13 | ) | | 178 |
| | 30 |
| | 148 |
|
Other income and (deductions) |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Interest expense, net | (13 | ) | | (12 | ) | | (1 | ) | | (38 | ) | | (37 | ) | | (1 | ) |
Other, net | 4 |
| | 3 |
| | 1 |
| | 10 |
| | 9 |
| | 1 |
|
Total other income and (deductions) | (9 | ) | | (9 | ) | | — |
| | (28 | ) | | (28 | ) | | — |
|
Income before income taxes | 50 |
|
| 63 |
| | (13 | ) | | 150 |
|
| 2 |
| | 148 |
|
Income taxes | 19 |
| | 19 |
| | — |
| | 43 |
| | 18 |
| | (25 | ) |
Net income (loss) | $ | 31 |
| | $ | 44 |
| | $ | (13 | ) | | $ | 107 |
| | $ | (16 | ) | | $ | 123 |
|
_________
| |
(a) | DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for natural gas sales. DPL believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements because they provide information that can be used to evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense and Revenue net of fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
Net Income (Loss)
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. DPL's Net income for the three months ended September 30, 2017, was lower than the same period in 2016 as a result of the merger commitment reallocation from DPL to Exelon that decreased Operating and maintenance expense in 2016, partially offset by an increase in Revenue net of purchased power and fuel expense primarily resulting from higher electric distribution and natural gas revenues as a result of the distribution rate increases approved by the DPSC effective July 2016 and December 2016 and by the MDPSC effective February 2017.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. DPL's Net income (loss) for the nine months ended September 30, 2017, was higher than the same period in 2016 as a result of an increase in Revenue net of purchased power and fuel expense primarily resulting from higher electric distribution and natural gas revenues as a result of the distribution rate increases approved by the DPSC effective July 2016 and December 2016 and by the MDPSC effective February 2017, lower Operating and maintenance expense due to merger-related costs recognized in March 2016, lower uncollectible accounts expense, and the deferral of merger-related costs to a regulatory asset in 2017, and a decrease in income tax reserves in the first quarter of 2017 for uncertain tax positions related to the deductibility of certain merger commitments.
Revenues Net of Purchased Power and Fuel Expense
Operating revenues include revenue from the distribution and supply of electricity to DPL’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric and natural gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All DPL customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers' choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2017 and 2016, consisted of the following:
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Electric | 51 | % | | 49 | % | | 52 | % | | 51 | % |
Natural Gas | 53 | % | | 51 | % | | 35 | % | | 32 | % |
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:
|
| | | | | | | | | | | |
| September 30, 2017 | | September 30, 2016 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 78,426 |
| | 15.0 | % | | 79,501 |
| | 15.4 | % |
Natural Gas | 155 |
| | 0.1 | % | | 157 |
| | 0.1 | % |
Retail deliveries purchased from competitive electric generation suppliers represented 53% and 54% of DPL’s retail kWh sales to Delaware customers and 48% and 48% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 51% and 53% of DPL's retail kWh sales to Delaware customers and 47% and 47% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.
Operating revenues include transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Natural gas operating revenue includes sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated gas revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
Purchased power expense consists of the cost of electricity purchased by DPL to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased fuel expense consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales.
The changes in DPL’s operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease)
| | Increase (Decrease)
|
| Electric | | Gas | | Total | | Electric | | Gas | | Total |
Weather | $ | (6 | ) | | $ | 1 |
| | $ | (5 | ) | | $ | (9 | ) | | $ | (13 | ) | | $ | (22 | ) |
Volume | 2 |
| | (1 | ) | | 1 |
| | 3 |
| | 10 |
| | 13 |
|
Pricing - distribution revenues | 17 |
| | — |
| | 17 |
| | 49 |
| | 2 |
| | 51 |
|
Regulatory required programs | (3 | ) | | — |
| | (3 | ) | | (2 | ) | | — |
| | (2 | ) |
Transmission revenues | 5 |
| | — |
| | 5 |
| | 4 |
| | — |
| | 4 |
|
Other | 3 |
| | (1 | ) | | 2 |
| | 5 |
| | (3 | ) | | 2 |
|
Total increase (decrease) | $ | 18 |
| | $ | (1 | ) | | $ | 17 |
| | $ | 50 |
| | $ | (4 | ) | | $ | 46 |
|
Revenue Decoupling. DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.
In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.
Weather. The demand for electricity and natural gas in areas not subject to the BSA is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2017 compared to the same periods in 2016, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable weather conditions in DPL's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's electric service territory and a 30-year period in DPL's natural gas service territory. The changes in heating and cooling degree days in DPL’s service territory for the three and nine months ended September 30, 2017 compared to the same periods in 2016 and normal weather consisted of the following:
|
| | | | | | | | | | | | | | |
Electric Service Territory | | | | | % Change |
Three Months Ended September 30, | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 24 |
| | 14 |
| | 33 |
| | 71.4 | % | | (27.3 | )% |
Cooling Degree-Days | 867 |
| | 1,103 |
| | 856 |
| | (21.4 | )% | | 1.3 | % |
| | | | | | | | | |
Nine Months Ended September 30, | | | | | | | | | |
Heating Degree-Days | 2,384 |
| | 2,812 |
| | 2,933 |
| | (15.2 | )% | | (18.7 | )% |
Cooling Degree-Days | 1,228 |
| | 1,410 |
| | 1,184 |
| | (12.9 | )% | | 3.7 | % |
|
| | | | | | | | | | | | | | |
Natural Gas Service Territory | | | | | % Change |
Three Months Ended September 30, | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 28 |
| | 20 |
| | 42 |
| | 40.0 | % | | (33.3 | )% |
| | | | | | | | | |
Nine Months Ended September 30, | | | | | | | | | |
Heating Degree-Days | 2,431 |
| | 2,913 |
| | 3,062 |
| | (16.5 | )% | | (20.6 | )% |
Volume. The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2017 compared to the same periods in 2016, primarily reflects the impact of increased natural gas average customer usage and customer growth.
Pricing—Distribution Revenues. The increase in electric operating revenues net of purchased power expense as a result of pricing for the three and nine months ended September 30, 2017 compared to the same periods in 2016 was primarily due to the impact of higher electric distribution and natural gas rates charged to Delaware customers that became effective in July and December 2016 and the impact of higher electric distribution rates charged to Maryland customers that became effective in February 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the change in operatingPrograms represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs.programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return.return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in DPL's Consolidated Statements of OperationsOperating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and Comprehensive Income. Refertherefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and maintenance expensePurchased power and Depreciationfuel expense. DPL recovers electricity and amortization expense discussion belowREC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on included programs.the presentation of DPL's revenue disaggregation.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense$32 million for the three months ended September 30, 2017March 31, 2023, compared to the same period in 20162022, respectively, in Purchased power and fuel expense is a resultfully offset in Operating revenues as part of higher rates effective June 1, 2017 related to increases in transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months
regulatory required programs.
ended September 30, 2017 compared to the same periodThe changes in 2016 is a result of higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.
Other. Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs, and recoveries of other taxes.
Operating and Maintenance Expensemaintenance expense consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Increase (Decrease) | | Nine Months Ended September 30, | | Increase (Decrease) |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating and maintenance expense - baseline | $ | 76 |
| | $ | 50 |
| | $ | 26 |
| | $ | 221 |
| | $ | 328 |
| | $ | (107 | ) |
Operating and maintenance expense - regulatory required programs(a) | 3 |
| | 5 |
| | (2 | ) | | 6 |
| | 10 |
| | (4 | ) |
Total operating and maintenance expense | $ | 79 |
| | $ | 55 |
| | $ | 24 |
| | $ | 227 |
| | $ | 338 |
| | $ | (111 | ) |
_________
| | | | | | | |
(a) | OperatingThree Months Ended March 31, 2023 | | |
| (Decrease) Increase | | |
Labor, other benefits, contracting and maintenance expenses for regulatorymaterials | $ | (3) | | | |
Storm-related costs | (3) | | | |
BSC and PHISCO costs | (1) | | | |
Credit loss expense | (1) | | | |
Pension and non-pension postretirement benefits expense | 1 | | | |
| | | |
| (7) | | | |
Regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues. | 1 | | | |
Total decrease | $ | (6) | | | |
The changes in OperatingDepreciation and maintenanceamortization expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease)
| | Increase (Decrease)
|
Baseline | | | |
Labor, other benefits, contracting and materials | $ | 3 |
| | $ | 3 |
|
Storm-related costs | (2 | ) | | 4 |
|
Uncollectible accounts expense | (2 | ) | | (7 | ) |
Remeasurement of AMI-related regulatory asset(a) | (1 | ) | | (2 | ) |
Deferral of merger-related costs to regulatory asset | — |
| | (6 | ) |
BSC and PHISCO allocations(b) | (1 | ) | | (15 | ) |
Merger commitments(c) | 27 |
| | (79 | ) |
Other | 2 |
| | (5 | ) |
| 26 |
| | (107 | ) |
Regulatory required programs | | | |
Purchased power administrative costs | (2 | ) | | (4 | ) |
Total increase (decrease) | $ | 24 |
| | $ | (111 | ) |
_________
| | | | | | | |
(a) | Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.Three Months Ended March 31, 2023 |
| |
(b) | Primarily related to merger severance and compensation costs recognized in 2016.Increase (Decrease) |
| |
(c)Depreciation and amortization(a) | Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.$ |
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease)
| | Increase (Decrease)
|
Depreciation expense(a) | $ | 3 |
| | $ | 9 |
|
Regulatory asset amortization | — |
| | (2 | ) |
Regulatory required programs(b)
| (2 | ) | | (3 | ) |
Total increase | $ | 1 |
| | $ | 4 |
|
_________
7 | | | |
(a)Regulatory asset amortization | Depreciation expense increased due to higher depreciation rates in Maryland effective February 2017 and due to ongoing capital expenditures.(1) |
| | |
(b) | Depreciation and amortization expenses for regulatoryRegulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. A partially offsetting amount has been reflected in Operating revenues and Operating and maintenance expense. | (3) | | | |
Total increase | $ | 3 | | | |
Taxes Other Than Income
Taxes other than income for the three__________
(a)Reflects ongoing capital expenditures, higher distribution depreciation rates in Maryland effective March 2022 and nine months endedhigher transmission depreciation rates effective September 30, 2017 compared to the same periods in 2016 remained relatively constant.2022.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.
Other, Net
Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.
Effective Income Tax Rate
DPL's effective income tax rate was 38.0%rateswere 16.7% and 30.2%6.7% for the three months ended September 30, 2017March 31, 2023 and 2016,2022, respectively. DPL's effective income tax rate was 28.7% and 900.0% for the nine months ended September 30, 2017 and 2016, respectively. In the first quarter of 2017, DPL decreased its liability for unrecognized tax benefits by $16 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate. See Note 12 -7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
DPL Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Weather - Normal % Change | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | | | 2017 | | 2016 | | |
Retail Deliveries(a) | | | | | | | | | | | | | | | |
Residential | 1,439 |
| | 1,601 |
| | (10.1 | )% | | (2.2 | )% | | 3,843 |
| | 4,066 |
| | (5.5 | )% | | 0.4 | % |
Small commercial & industrial | 636 |
| | 642 |
| | (0.9 | )% | | 3.2 | % | | 1,693 |
| | 1,746 |
| | (3.0 | )% | | (0.9 | )% |
Large commercial & industrial | 1,245 |
| | 1,250 |
| | (0.4 | )% | | 4.1 | % | | 3,440 |
| | 3,492 |
| | (1.5 | )% | | 0.3 | % |
Public authorities & electric railroads | 10 |
| | 9 |
| | 11.1 | % | | 11.1 | % | | 35 |
| | 35 |
| | — | % | | — | % |
Total retail deliveries | 3,330 |
| | 3,502 |
| | (4.9 | )% | | 1.2 | % | | 9,011 |
| | 9,339 |
| | (3.5 | )% | | 0.1 | % |
|
| | | | | |
| As of September 30, |
Number of Electric Customers | 2017 | | 2016 |
Residential | 458,790 |
| | 455,640 |
|
Small commercial & industrial | 60,542 |
| | 60,034 |
|
Large commercial & industrial
| 1,406 |
| | 1,414 |
|
Public authorities & electric railroads | 633 |
| | 643 |
|
Total | 521,371 |
| | 517,731 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Nine Months Ended September 30, | | % Change |
Electric Revenue | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Sales(a) | | | | | | | | | | | |
Residential | $ | 183 |
| | $ | 200 |
| | (8.5 | )% | | $ | 508 |
| | $ | 522 |
| | (2.7 | )% |
Small commercial & industrial | 49 |
| | 48 |
| | 2.1 | % | | 138 |
| | 143 |
| | (3.5 | )% |
Large commercial & industrial | 26 |
| | 24 |
| | 8.3 | % | | 77 |
| | 74 |
| | 4.1 | % |
Public authorities & electric railroads | 3 |
| | 2 |
| | 50.0 | % | | 11 |
| | 9 |
| | 22.2 | % |
Total retail | 261 |
| | 274 |
| | (4.7 | )% | | 734 |
| | 748 |
| | (1.9 | )% |
Other revenue(b) | 48 |
| | 40 |
| | 20.0 | % | | 132 |
| | 124 |
| | 6.5 | % |
Total electric revenue(c) | $ | 309 |
| | $ | 314 |
| | (1.6 | )% | | $ | 866 |
| | $ | 872 |
| | (0.7 | )% |
_________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and transmission. |
| |
(b) | Other revenue includes transmission revenue from PJM and wholesale electric revenues. |
| |
(c) | Includes operating revenues from affiliates totaling $2 million for the three months ended September 30, 2017 and 2016 and $6 million for the nine months ended September 30, 2017 and 2016. |
DPL Natural Gas Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Weather - Normal % Change | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change |
Retail Deliveries to Customers (in mmcf) | 2017 | | 2016 | | | | 2017 | | 2016 | | |
Retail Deliveries | | | | | | | | | | | | | | | |
Retail sales | 1,069 |
| | 1,121 |
| | (4.6 | )% | | (6.4 | )% | | 8,679 |
| | 9,253 |
| | (6.2 | )% | | 6.5 | % |
Transportation & other | 1,197 |
| | 1,166 |
| | 2.7 | % | | 2.4 | % | | 4,690 |
| | 4,455 |
| | 5.3 | % | | 7.9 | % |
Total natural gas deliveries | 2,266 |
| | 2,287 |
| | (0.9 | )% | | (2.0 | )% | | 13,369 |
| | 13,708 |
| | (2.5 | )% | | 7.0 | % |
|
| | | | | |
| As of September 30, |
Number of Gas Customers | 2017 | | 2016 |
Residential | 121,238 |
| | 120,075 |
|
Commercial & industrial | 9,700 |
| | 9,656 |
|
Transportation & other | 155 |
| | 157 |
|
Total | 131,093 |
| | 129,888 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Nine Months Ended September 30, | | % Change |
Natural Gas Revenue | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Sales(a) | | | | | | | | | | | |
Retail sales | $ | 12 |
| | $ | 13 |
| | (7.7 | )% | | $ | 87 |
| | $ | 87 |
| | — | % |
Transportation & other(b) | 6 |
| | 4 |
| | 50.0 | % | | 18 |
| | 15 |
| | 20.0 | % |
Total natural gas revenues | $ | 18 |
| | $ | 17 |
| | 5.9 | % | | $ | 105 |
| | $ | 102 |
| | 2.9 | % |
__________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas. |
| |
(b) | Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. |
Results of Operations -— ACE
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Favorable (Unfavorable) Variance | | | | |
| 2023 | | 2022 | | | | | | |
Operating revenues | $ | 353 | | | $ | 349 | | | $ | 4 | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Operating expenses | | | | | | | | | | | |
Purchased power | 148 | | | 178 | | | 30 | | | | | | | |
Operating and maintenance | 81 | | | 84 | | | 3 | | | | | | | |
Depreciation and amortization | 67 | | | 47 | | | (20) | | | | | | | |
Taxes other than income taxes | 2 | | | 2 | | | — | | | | | | | |
Total operating expenses | 298 | | | 311 | | | 13 | | | | | | | |
| | | | | | | | | | | |
Operating income | 55 | | | 38 | | | 17 | | | | | | | |
Other income and (deductions) | | | | | | | | | | | |
Interest expense, net | (16) | | | (14) | | | (2) | | | | | | | |
Other, net | 5 | | | 3 | | | 2 | | | | | | | |
Total other income and (deductions) | (11) | | | (11) | | | — | | | | | | | |
Income before income taxes | 44 | | | 27 | | | 17 | | | | | | | |
Income taxes | 11 | | | 1 | | | (10) | | | | | | | |
Net income | $ | 33 | | | $ | 26 | | | $ | 7 | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating revenues | $ | 370 |
| | $ | 421 |
| | $ | (51 | ) | | $ | 915 |
| | $ | 982 |
| | $ | (67 | ) |
Purchased power expense | 176 |
| | 221 |
| | 45 |
| | 442 |
| | 520 |
| | 78 |
|
Revenues net of purchased power expense(a) | 194 |
| | 200 |
| | (6 | ) | | 473 |
| | 462 |
| | 11 |
|
Other operating expenses | | | | |
| | | | | |
|
Operating and maintenance | 72 |
| | 67 |
| | (5 | ) | | 225 |
| | 346 |
| | 121 |
|
Depreciation and amortization | 41 |
| | 49 |
| | 8 |
| | 113 |
| | 130 |
| | 17 |
|
Taxes other than income | 2 |
| | 1 |
| | (1 | ) | | 6 |
| | 6 |
| | — |
|
Total other operating expenses | 115 |
| | 117 |
| | 2 |
| | 344 |
| | 482 |
| | 138 |
|
Gain on sales of assets | — |
| | — |
| | — |
| | — |
| | 1 |
| | (1 | ) |
Operating income (loss) | 79 |
| | 83 |
| | (4 | ) | | 129 |
| | (19 | ) | | 148 |
|
Other income and (deductions) | | | | |
| | | | | |
|
Interest expense, net | (15 | ) | | (15 | ) | | — |
| | (46 | ) | | (47 | ) | | 1 |
|
Other, net | 1 |
| | 2 |
| | (1 | ) | | 6 |
| | 8 |
| | (2 | ) |
Total other income and (deductions) | (14 | ) |
| (13 | ) | | (1 | ) | | (40 | ) |
| (39 | ) | | (1 | ) |
Income (loss) before income taxes | 65 |
|
| 70 |
| | (5 | ) | | 89 |
|
| (58 | ) | | 147 |
|
Income taxes | 24 |
| | 23 |
| | (1 | ) | | 12 |
| | (8 | ) | | (20 | ) |
Net income (loss) | $ | 41 |
| | $ | 47 |
| | $ | (6 | ) | | $ | 77 |
| | $ | (50 | ) | | $ | 127 |
|
_________
| |
(a) | ACE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. ACE believes Revenue net of purchased power expense is a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. ACE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. |
Net Income (Loss)
Three Months Ended September 30, 2017March 31, 2023 Compared to Three Months Ended September 30, 2016. ACE'sMarch 31, 2022. Net income for the three months ended September 30, 2017, was lower than the same period in 2016, increased by $7 million primarily due to a decreasehigher transmission rates and decreases in Revenue net of purchased power expense resulting from lower distribution revenues due to lower average customer usage and unfavorable weather related sales, partially offset by the impact of distribution rate increases approved by the NJBPU effective August 2016.various operating expenses.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. ACE's Net income (loss) for the nine months ended September 30, 2017, was higher than the same periodThe changes in 2016, primarily due to an increase in Revenue net of purchased power expense resulting from higher electric distribution revenues as a result of a distribution rate increase approved by the NJBPU effective August 2016, lower Operating and maintenance expense mostly due to merger-related costs recognized in March 2016 and a decrease in income tax reserves in the first quarter 2017 for uncertain tax positions related to the deductibility of certain merger commitments.
Revenues Net of Purchased Power Expense
Operating revenues include revenue from the distribution and supply of electricity to ACE’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All ACE customers have the choice to purchase electricity from competitive electric generation suppliers. The customer's choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2017, compared to the same periods in 2016, consisted of the following:
| | | | | | | |
| Three Months Ended March 31, 2023 | | |
| Increase (Decrease) | | |
| | | |
| | | |
Distribution | $ | 8 | | | |
Transmission | 12 | | | |
| | | |
| 20 | | | |
| | | |
| | | |
| | | |
| | | |
Regulatory required programs | (16) | | | |
Total increase | $ | 4 | | | |
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Electric | 44 | % | | 44 | % | | 48 | % | | 46 | % |
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:
|
| | | | | | | | | | | |
| September 30, 2017 | | September 30, 2016 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 91,219 |
| | 17 | % | | 96,837 |
| | 18 | % |
Operating revenues include revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, revenue from the resale in the PJM wholesale markets for energy and capacity purchased under contacts with unaffiliated NUGs, and revenue from transmission enhancement credits.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Purchased power expense consists of the cost of electricity purchased by ACE to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.
The changes in ACE’s operating revenue net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Weather | $ | (5 | ) | | $ | (7 | ) |
Volume | (12 | ) | | (15 | ) |
Pricing - distribution revenues | 16 |
| | 36 |
|
Regulatory required programs | (9 | ) | | (19 | ) |
Transmission revenues | 4 |
| | 17 |
|
Other | — |
| | (1 | ) |
Total (decrease) increase | $ | (6 | ) | | $ | 11 |
|
Weather. Revenue Decoupling. The demand for electricity is affected by weather conditions. With respectand customer usage. However, Operating revenues from electric distribution in New Jersey are not impacted by abnormal weather or usage per customer as a result of the CIP which became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to the electric business, very warm weatherapproved target revenues established in summer monthsACE’s most recent distribution base rate case. The CIP is calculated annually, and very cold weather in winter months are referredrecovery is subject to as “favorable weather conditions” because these weathercertain conditions, result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the threeincluding an earnings test and nine months ended September 30, 2017 compared to the same periods in 2016, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable weather conditions in ACE's service territory.
For retail customers of ACE, distributionceilings on customer rate increases. While Operating revenues are not decoupled from the distribution of electricityimpacted by ACE, and thusabnormal weather or usage per customer, they are subject to variability due toimpacted by changes in customer consumption. Therefore, changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have a direct impact on reported distribution revenue for customers in ACE's service territory.
the number of customers.
| | | | | | | | | | | |
| As of March 31, |
Number of Electric Customers | 2023 | | 2022 |
Residential | 503,260 | | | 500,511 | |
Small commercial & industrial | 62,230 | | | 62,124 | |
Large commercial & industrial | 3,030 | | | 3,124 | |
Public authorities & electric railroads | 726 | | | 724 | |
Total | 569,246 | | | 566,483 | |
Heating and cooling degree days are quantitative indices that reflect the demandDistribution Revenue increased for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:
|
| | | | | | | | | | | | | | |
| | | Normal | | % Change |
| 2017 | | 2016 | | | 2017 vs. 2016 | | 2017 vs. Normal |
Three Months Ended September 30, | | | | | | | | | |
Heating Degree-Days | 23 |
| | 17 |
| | 42 |
| | 35.3 | % | | (45.2 | )% |
Cooling Degree-Days | 830 |
| | 1,006 |
| | 806 |
| | (17.5 | )% | | 3.0 | % |
| | | | | | |
|
| |
|
|
Nine Months Ended September 30, | | | | | | |
|
| |
|
|
Heating Degree-Days | 2,608 |
| | 2,938 |
| | 3,103 |
| | (11.2 | )% | | (16.0 | )% |
Cooling Degree-Days | 1,153 |
| | 1,267 |
| | 1,092 |
| | (9.0 | )% | | 5.6 | % |
Volume. During the three months ended September 30, 2017,March 31, 2023 compared to the same period in 2016, the decrease in operating revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, is primarily2022 due to lower average customer usage. During the nine months ended September 30, 2017 compared to the same period in 2016, primarily reflects lower average customer usage, partially offset by the impact of customer growth.
Pricing—Distribution Revenues. The increase in operating revenue net of purchased power expense for the three and nine months ended September 30, 2017, compared to the same periods in 2016, washigher distribution rates primarily due to the impactexpiration of higher electric distribution base rates charged to customers that became effective in August 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in ACE's Consolidated Statements of Operations and Comprehensive Income. Refercustomer credits related to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.TCJA tax benefits.
Transmission Revenues.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered and other billing adjustments. The increase inrecovered. Transmission revenue net of purchased power expenseincreased for thethree months ended September 30, 2017March 31, 2023 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and related2022, primarily due to increases in transmission plantcapital investment and operating expenses.underlying costs.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bond Charge, and BGS procurement and administrative costs. The increaseriders are designed to provide full and current cost recovery as well as a return in revenue netcertain instances. The costs of purchasedthese programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the ninepresentation of ACE's revenue disaggregation.
The decrease of $30 million for the three months ended September 30, 2017March 31, 2023 compared to the same period in 20162022, in Purchased power expense is a resultfully offset in Operating revenues as part of higher rates effective June 1, 2017 and June 1, 2016 related to increasesregulatory required programs.
The changes in transmission plant investment and operating expenses.
Operating and Maintenance Expensemaintenance expense consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Increase (Decrease) | | Nine Months Ended September 30, | | Increase (Decrease) |
| 2017 | | 2016 | | | 2017 | | 2016 | |
Operating and maintenance expense - baseline | $ | 71 |
| | $ | 66 |
| | $ | 5 |
| | $ | 222 |
| | $ | 343 |
| | $ | (121 | ) |
Operating and maintenance expense - regulatory required programs(a) | 1 |
| | 1 |
| | — |
| | 3 |
| | 3 |
| | — |
|
Total operating and maintenance expense | $ | 72 |
| | $ | 67 |
| | $ | 5 |
| | $ | 225 |
| | $ | 346 |
| | $ | (121 | ) |
_________
| | | | | | | |
(a) | OperatingThree Months Ended March 31, 2023 | | |
| (Decrease) Increase | | |
Labor, other benefits, contracting and maintenance expenses for regulatorymaterials | $ | (2) | | | |
| | | |
Storm-related costs | (2) | | | |
| | | |
| | | |
Other | 2 | | | |
| (2) | | | |
| | | |
Regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.(a) | (1) | | | |
Total decrease | $ | (3) | | | |
(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.
The changes in OperatingDepreciation and maintenance amortizationexpense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Baseline | | | |
Labor, other benefits, contracting and materials | $ | 3 |
| | $ | 6 |
|
Storm-related costs | (3 | ) | | (2 | ) |
BSC and PHISCO allocations(a) | — |
| | (11 | ) |
Deferral of merger-related costs to regulatory asset | (9 | ) | | (9 | ) |
Merger commitments(b) | 10 |
| | (111 | ) |
Other | 4 |
| | 6 |
|
Total increase (decrease) | $ | 5 |
| | $ | (121 | ) |
_________
| | | | | | | |
(a) | Primarily related to merger severance and compensation costs recognized in 2016.Three Months Ended March 31, 2023 |
| |
(b) | Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.Increase |
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:
|
| | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| Increase (Decrease) | | Increase (Decrease) |
Depreciation expense(a) | $ | 1 |
| | $ | 4 |
|
Regulatory asset amortization | — |
| | (2 | ) |
Regulatory required programs(b) | (9 | ) | | (19 | ) |
Total decrease | $ | (8 | ) | | $ | (17 | ) |
_________
| |
Depreciation and amortization(a) | Depreciation expense increased due to ongoing capital expenditures.$ |
7 | | | |
(b)Regulatory asset amortization | — | | | |
Regulatory required programs decreased for the three and nine months ended September 30, 2017 compared to the same periods in 2016 as a result of lower revenue due to rate decreases effective October 2016 for the ACE Transition Bond Charge and Market Transition Charge Tax. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.(b) | 13 | | | |
Total increase | $ | 20 | | | |
Taxes Other Than Income
Taxes other than income for the three__________
(a)Reflects ongoing capital expenditures and nine months endedhigher transmission depreciation rates effective September 30, 2017 compared2022.
(b)Regulatory required programs increased primarily due to the same periodsregulatory asset amortization of the PPA termination obligation which is fully offset in 2016, remained relatively constant.Operating revenues.
Gain on sales of assets
Gain on sales of assets for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.
Other, Net
Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016, remained relatively constant.
Effective Income Tax Rate
ACE's effective income tax rate was 36.9%rates were 25.0% and 32.9%3.7% for the three months ended September 30, 2017March 31, 2023 and 2016,2022, respectively. ACE's effective income tax rate was 13.5% and 13.8% for the nine months ended September 30, 2017 and 2016, respectively. In the first quarter of 2017, ACE decreased its liability for unrecognized tax benefits by $22 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate. See Note 12 -7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
ACE Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Weather - Normal % Change | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | | | 2017 | | 2016 | | |
Retail Deliveries(a) | | | | | | | | | | | | | | | |
Residential | 1,349 |
| | 1,575 |
| | (14.3 | )% | | (10.4 | )% | | 3,042 |
| | 3,327 |
| | (8.6 | )% | | (6.0 | )% |
Small commercial & industrial | 407 |
| | 426 |
| | (4.5 | )% | | (1.9 | )% | | 992 |
| | 998 |
| | (0.6 | )% | | 0.8 | % |
Large commercial & industrial | 939 |
| | 1,032 |
| | (9.0 | )% | | (6.3 | )% | | 2,557 |
| | 2,705 |
| | (5.5 | )% | | (4.6 | )% |
Public authorities & electric railroads | 9 |
| | 11 |
| | (18.2 | )% | | (18.2 | )% | | 33 |
| | 35 |
| | (5.7 | )% | | (5.7 | )% |
Total retail deliveries | 2,704 |
| | 3,044 |
| | (11.2 | )% | | (7.8 | )% | | 6,624 |
| | 7,065 |
| | (6.2 | )% | | (4.5 | )% |
|
| | | | | |
| As of September 30, |
Number of Electric Customers | 2017 | | 2016 |
Residential | 486,212 |
| | 483,542 |
|
Small commercial & industrial | 60,982 |
| | 60,875 |
|
Large commercial & industrial | 3,726 |
| | 3,796 |
|
Public authorities & electric railroads | 633 |
| | 593 |
|
Total | 551,553 |
| | 548,806 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | % Change | | Nine Months Ended September 30, | | % Change |
Electric Revenue | 2017 | | 2016 | | | 2017 | | 2016 | |
Retail Sales(a) | | | | | | | | | | | |
Residential | $ | 211 |
| | $ | 249 |
| | (15.3 | )% | | $ | 484 |
| | $ | 530 |
| | (8.7 | )% |
Small commercial & industrial | 53 |
| | 55 |
| | (3.6 | )% | | 129 |
| | 133 |
| | (3.0 | )% |
Large commercial & industrial | 49 |
| | 57 |
| | (14.0 | )% | | 143 |
| | 158 |
| | (9.5 | )% |
Public authorities & electric railroads | 3 |
| | 4 |
| | (25.0 | )% | | 10 |
| | 10 |
| | — | % |
Total retail | 316 |
| | 365 |
| | (13.4 | )% | | 766 |
| | 831 |
| | (7.8 | )% |
Other revenue(b) | 54 |
| | 56 |
| | (3.6 | )% | | 149 |
| | 151 |
| | (1.3 | )% |
Total electric revenue(c) | $ | 370 |
| | $ | 421 |
| | (12.1 | )% | | $ | 915 |
| | $ | 982 |
| | (6.8 | )% |
_________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and transmission. |
| |
(b) | Other revenue includes transmission revenue from PJM and wholesale electric revenues. |
| |
(c) | Includes operating revenues from affiliates totaling $0 million and $1 million for the three months ended September 30, 2017 and 2016, respectively, and $2 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively. |
Liquidity and Capital Resources (All Registrants)
Exelon activity presented below includes the activity of PHI, Pepco, DPL and ACE, from the PHI Merger effective date of March 24, 2016 through September 30, 2017. Exelon prior year activity is unadjusted for the effects of the PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI's activity is presented in two separate reporting periods, the legacy PHI activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL and ACE the activity presented below include its activity for the nine months ended September 30, 2017 and 2016. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of $9$4.0 billion. In addition, Generation has $525 millionin bilateral facilities with banks which have various expirations between December 2017 and January 2019. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters”Matters and Cash Requirements” section below for further discussion.additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd, PECO, BGE, Pepco, DPL and ACE operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 1110 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further discussion ofadditional information on the Registrants’ debt and credit agreements.
NRC Minimum Funding Requirements
NRC regulations require that licenseesCash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommissionCash Flows for only 2022. The Exelon Consolidated Statement of Cash Flows for the facility. These NRC minimum funding levels are based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 13 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information on the NRC minimum funding requirements.
If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. A shortfall could require Exelon to post parental guarantees for Generation’s share of the obligations. However, the amount of any required guarantees will ultimately depend on the decommissioning approach adopted at each site, the associated level of costs, and the decommissioning trust fund investment performance going forward. Within two years after shutting down a plant, Generation must submit a post-shutdown decommissioning activities report (PSDAR) to the NRC that includes the planned option for decommissioning the site. As discussed in Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements, Generation filed its biennial decommissioning funding status report with the NRC onthree months ended March 31, 2017 and demonstrated adequate funding assurance for all nuclear units currently operating. As2022 includes one month of September 30, 2017, across the four alternative decommissioning approaches available, Generation estimates a parental guarantee of up to $115 millioncash flows from Exelon could be required for TMI, dependent upon the ultimate decommissioning approach selected. TMI passes the NRC minimum funding test based on the unit's 2019 retirement date under the decommissioning approach currently considered to be the most likely. For Oyster Creek, none of the alternative decommissioning approaches available would require Exelon to post a parental guarantee.Generation.
Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs.
However, the NRC must approve an additional exemption in order for the plant’s owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s). While the ultimate amounts may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the United States Department of Energy reimbursement agreements or future litigation, across the four alternative decommissioning approaches available, if TMI or Oyster Creek were to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $190 million and $150 million net of taxes, respectively, dependent upon the ultimate decommissioning approach selected. Under the decommissioning approach currently considered the most likely for each unit, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $170 million and $130 million net of taxes, respectively, if TMI or Oyster Creek were to fail to obtain the exemption.
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of September 30, 2017. See Note 17 - Earnings Per Share and Equity of the Combined Notes to Consolidated Financial Statements for further information on the issuance of common stock.
Cash Flows from Operating Activities
General
Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers.
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, competitive suppliers, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.
See Note 3 — Regulatory Matters of the 2022 Form 10-K and Notes 3 — Regulatory Matters and 2412 — Commitments and Contingenciesof the Combined Notes to Consolidated Financial Statements of the Exelon 2016 Form 10-K for further discussion ofadditional information on regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the nine months ended September 30, 2017 and 2016:
|
| | | | | | | | | | | |
| Nine Months Ended September 30, | | |
| 2017 | | 2016(c) | | Variance |
Net income | $ | 1,911 |
| | $ | 956 |
| | $ | 955 |
|
Add (subtract): | | | | | |
Non-cash operating activities(a) | 5,011 |
| | 5,946 |
| | (935 | ) |
Pension and non-pension postretirement benefit contributions | (344 | ) | | (283 | ) | | (61 | ) |
Income taxes | 167 |
| | 527 |
| | (360 | ) |
Changes in working capital and other noncurrent assets and liabilities(b) | (1,003 | ) | | (516 | ) | | (487 | ) |
Option premiums received (paid), net | 35 |
| | (24 | ) | | 59 |
|
Collateral (posted) received, net | (100 | ) | | 757 |
| | (857 | ) |
Net cash flows provided by operations | $ | 5,677 |
| | $ | 7,363 |
| | $ | (1,686 | ) |
_________ | |
(a) | Represents, when applicable, depreciation, amortization and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and other postretirement benefit expense, equitychange in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, PHI merger commitment and severance charges, and other non-cash charges. See Note 19 - Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for further detail on non-cash operating activity. |
| |
(b) | Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt. |
| |
(c) | Includes PHI Consolidated activity from March 24, 2016 to September 30, 2016. |
Pension and Other Postretirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications.
On October 3, 2017, the US Department of Treasury and IRS released final regulations updating the mortality tables to be used for defined benefit pension plan funding, as well as the valuation of lump sum and other accelerated distribution options, effective for plan years beginning in 2018. The new mortality tables reflect improved projected life expectancy as compared to the existing table, which is generally expected to increase minimum pension funding requirements, Pension Benefit Guaranty Corporation premiums and the value of lump sum distributions. The IRS will permit plan sponsors the option of using existing mortality tables for determining minimum funding requirements for 2018. The one-year delay does not apply for use of the mortality tables to determine the present value of lump sum distributions. Exelon is still evaluating any potential impacts of the new mortality tables.
OPEB funding generally follows accounting cost; however, Exelon’s management has historically considered several factors in determining the level of contributions to its funded other postretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery).
To the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contribution requirements in future years could increase. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
Tax Matters
The Registrants’ future cash flows from operating activities may be affected by the following tax matters:
Exelon appealed the Tax Court’s like-kind exchange decision in the third quarter of 2017 and expects that a payment of approximately $1.3 billion related to the like-kind exchange will be due, including $300 million attributable to ComEd, in the fourth quarter of 2017. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is
approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position.
Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. Any remaining amounts due to the IRS will be paid by Exelon in the fourth quarter of 2017. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. See Note 12 - Income Taxes for further discussion of the like-kind exchange tax position.
State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax, property taxes and other taxes or the imposition, extension or permanence of temporary tax increases. On July 6, 2017, Illinois enacted Senate Bill 9, which permanently increased Illinois’ total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future cash taxes. See Note 12 - Income Taxes for further discussion of the Illinois tax rate change.
Cash flows from operations for the ninethree months ended September 30, 2017March 31, 2023 and 20162022 by Registrant were as follows:Registrant:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Increase (decrease) in cash flows from operating activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Net income (loss) | $ | 71 | | | $ | 53 | | | $ | (40) | | | $ | 2 | | | $ | 25 | | | $ | 19 | | | $ | 4 | | | $ | 7 | |
Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | |
Non-cash operating activities | (683) | | | (126) | | | (7) | | | (61) | | | (8) | | | (17) | | | (9) | | | 14 | |
Option premiums (paid), net | 39 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Collateral (paid) received, net | (1,356) | | | (47) | | | — | | | (52) | | | (226) | | | (26) | | | (150) | | | (41) | |
Income taxes | (54) | | | 17 | | | 20 | | | 25 | | | 15 | | | 7 | | | 10 | | | 5 | |
Pension and non-pension postretirement benefit contributions | 530 | | | 153 | | | 12 | | | 48 | | | 60 | | | 1 | | | 1 | | | 6 | |
Regulatory assets and liabilities, net | (293) | | | (330) | | | 19 | | | (23) | | | 45 | | | 4 | | | 27 | | | 6 | |
Changes in working capital and other assets and liabilities | 448 | | | 24 | | | 23 | | | 93 | | | 113 | | | 70 | | | 30 | | | 3 | |
(Decrease) increase in cash flows from operating activities | $ | (1,298) | | | $ | (256) | | | $ | 27 | | | $ | 32 | | | $ | 24 | | | $ | 58 | | | $ | (87) | | | $ | — | |
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
Exelon | $ | 5,677 |
| | $ | 7,363 |
|
Generation | 2,270 |
| | 3,723 |
|
ComEd | 1,120 |
| | 1,749 |
|
PECO | 603 |
| | 582 |
|
BGE | 704 |
| | 660 |
|
Pepco | 348 |
| | 504 |
|
DPL | 292 |
| | 267 |
|
ACE | 158 |
| | 315 |
|
|
| | | | | | | | | | | | |
| Successor | | | Predecessor |
| Nine Months Ended September 30, 2017 |
| March 24, 2016 to September 30, 2016 |
| | January 1, 2016 to March 23, 2016 |
PHI | $ | 797 |
| | $ | 546 |
| | | $ | 264 |
|
Changes in the Registrants'cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significantSee above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for the ninethree months ended September 30, 2017March 31, 2023 and 20162022 were as follows:
Generation•See Note 15 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.
Depending•Changes in collateral depended upon whether Generation iswas in a net mark-to-market liability or asset position, and collateral may behave been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differdiffered depending on whether the transactions arewere on an exchange or in the OTCover-the-counter markets. DuringChanges in collateral for the nine months ended September 30, 2017 and 2016, Generation had net (payments)/collectionsRegistrants are dependent upon the credit exposure of counterparty cash collateral of $(77) million and $759 million, respectively, primarily dueprocurement contracts that may require suppliers to market conditions that resulted in changes to Generation’s net mark-to-market position.
During the nine months ended September 30, 2017 and 2016, Generation had net (payments) collections of approximately $(35) million and $24 million, respectively, related to purchases and sales of options.post collateral. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.
ComEd
During nine months ended September 30, 2017 and 2016, ComEd posted approximately $24 million and $2 millionamount of cash collateral with PJM, respectively. ComEd’s collateral posted with PJM has increased year over year primarilyreceived from external counterparties decreased due to an increase in ComEd’s RPM credit requirements and peak market activity with PJM. As of September 30, 2017 and 2016, ComEd had approximately $47 million and $33 million cash collateral posted with PJM, respectively.decreasing energy prices. See Note 9 — Derivative Financial Instruments for additional information.
For further discussion regarding changes in non-cash operating activities, please refer to•See Note 19 - Supplemental Financial Information7 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
•Changes in Pension and non-pension postretirement benefit contributions relates to Exelon receiving an updated valuation of its pension and OPEB to reflect census data as of January 1, 2023. See Note 8 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements.Statements for additional information.
•Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $72 million and $50 million for the three months ended March 31, 2023 and 2022, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $33 million, $14 million, $5 million, and $4 million for the three months ended March 31, 2023 and $26 million, $13 million, $6 million, and $2 million for the three months ended March 31, 2022, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31,
2023 and 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
•Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $125 million and for Generation total $323 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement which was entered into in April 2020. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the three months ended March 31, 2023, the established pricing resulted in a ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.
Cash Flows from Investing Activities
CashThe following table provides a summary of the change in cash flows used infrom investing activities for the ninethree months ended September 30, 2017March 31, 2023 and 20162022 by Registrant were as follows: Registrant:
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 |
| 2016 |
Exelon | $ | (5,810 | ) | | $ | (13,219 | ) |
Generation | (1,903 | ) | | (3,278 | ) |
ComEd | (1,731 | ) | | (1,919 | ) |
PECO | (457 | ) | | (438 | ) |
BGE | (586 | ) | | (614 | ) |
Pepco | (439 | ) | | (435 | ) |
DPL | (293 | ) | | (254 | ) |
ACE | (241 | ) | | (227 | ) |
|
| | | | | | | | | | | | |
| Successor | | | Predecessor |
| Nine Months Ended September 30, 2017 |
| March 24, 2016 to September 30, 2016 | |
| January 1, 2016 to March 23, 2016 |
PHI | $ | (991 | ) |
| $ | (631 | ) | | | $ | (343 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Increase (decrease) in cash flows from investing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Capital expenditures | $ | 41 | | | $ | — | | | $ | 9 | | | $ | (47) | | | $ | (152) | | | $ | (46) | | | $ | (31) | | | $ | (74) | |
| | | | | | | | | | | | | | | |
Investment in NDT fund sales, net | 28 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Collection of DPP | (169) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Proceeds from sales of assets and businesses | (16) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Other investing activities | 64 | | | (6) | | | (2) | | | — | | | 6 | | | 7 | | | (1) | | | — | |
(Decrease) increase in cash flows from investing activities | $ | (52) | | | $ | (6) | | | $ | 7 | | | $ | (47) | | | $ | (146) | | | $ | (39) | | | $ | (32) | | | $ | (74) | |
Significant investing cash flow impacts for the Registrants for ninethree months ended September 30, 2017March 31, 2023 and 20162022 were as follows:
Exelon
During the nine months ended September 30, 2017, Exelon had•Changes in capital expenditures of $23 million and $178 million relating are primarily due to the acquisitionstiming of ConEdison Solutionscash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the FitzPatrick facility, respectively. During the nine months ended September 30, 2016, Exelon had expenditures of $6.6 billion relating to the acquisition of PHI.
During the nine months ended September 30, 2016, Exelon had proceeds of $360 million as a result of early termination of direct financing leases.
Generation
During the nine months ended September 30, 2017, Exelon had expenditures of $23 million and $178 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively.
Capital Expenditure Spending
Generation
Generation has entered into several agreements to acquire equity interests in privately held and development stage entities which develop energy-related technologies. The agreements contain a series of scheduled investment commitments, including in-kind service contributions. There are anticipated expenditures remaining through 2019 to
fund anticipated planned capital and operating needs of the associated companies.Utility Registrants. See Note 242 — Commitments and ContingenciesDiscontinued Operations of the Combined Notes to Consolidated Financial Statements of the Exelon 2016 Form 10-K for further details of Generation’s equity interests.
Capital expenditures by Registrant for the nine months ended September 30, 2017 and 2016 and projected amounts for the full year 2017 are as follows:
|
| | | | | | | | | | | |
| Projected Full Year 2017(a) | | Nine Months Ended September 30, |
| 2017 | | 2016 |
Exelon(b) | $ | 8,075 |
| | $ | 5,556 |
| | $ | 6,368 |
|
Generation | 2,450 |
| | 1,654 |
| | 2,651 |
|
ComEd(c) | 2,200 |
| | 1,698 |
| | 1,950 |
|
PECO | 775 |
| | 537 |
| | 448 |
|
BGE | 925 |
| | 615 |
| | 611 |
|
Pepco | 625 |
| | 439 |
| | 392 |
|
DPL | 425 |
| | 294 |
| | 260 |
|
ACE | 300 |
| | 242 |
| | 227 |
|
|
| | | | | | | | | | | | | | | | |
| Projected Full Year 2017 (a) | | Successor | | | Predecessor |
| | Nine Months Ended September 30, 2017 |
| March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI(d) | $ | 1,375 |
| | $ | 995 |
| | $ | 624 |
| | | $ | 273 |
|
_________
| |
(a) | Total projected capital expenditures do not include adjustments for non-cash activity. |
| |
(b) | Includes corporate operations, BSC, and PHISCO rounded to the nearest $25 million. |
| |
(c) | The 2017 projections include approximately $274 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten year period, through 2022, to modernize and storm-harden its distribution system and to implement smart grid technology. |
| |
(d) | Includes PHISCO rounded to the nearest $25 million. |
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Approximately 37% and 21% of the projected 2017 capital expenditures at Generation are for the acquisition of nuclear fuel and growth (primarily new plant construction and distributed generation), respectively, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.
ComEd, PECO, BGE, Pepco, DPL and ACE
Approximately 93% of the projected 2017 capital expenditures at ComEd and 100% of the projected of the projected 2017 capital expenditures at PECO, BGE, Pepco, DPL, and ACE are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and the Utility Registrants' construction commitments under PJM’s RTEP. In addition to the capital expenditure for continuing projects, ComEd’s total expenditures include smart grid/smart meter technology required under EIMA.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted 2017 capital expenditures above reflect capital spending for remediation to be completed through 2018. Pepco, DPL and ACE have substantially completed their assessments and thus do not expect significant capital expenditures related to this guidanceGeneration prior to the separation.
•Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in 2017.April 2020.
The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
Cash Flows from Financing Activities
CashThe following table provides a summary of the change in cash flows provided by (used in)from financing activities for the ninethree months ended September 30, 2017March 31, 2023 and 20162022 by RegistrantRegistrant:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(Decrease) increase in cash flows from financing activities | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Changes in short-term borrowings, net | $ | (1,380) | | | $ | (168) | | | $ | (94) | | | $ | (285) | | | $ | 54 | | | $ | (124) | | | $ | 34 | | | $ | 144 | |
Long-term debt, net | (1,227) | | | 225 | | | — | | | — | | | (250) | | | (150) | | | — | | | (100) | |
Changes in intercompany money pool | — | | | — | | | (65) | | | — | | | (31) | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
Dividends paid on common stock | (26) | | | (43) | | | (1) | | | (4) | | | — | | | (6) | | | (1) | | | (2) | |
| | | | | | | | | | | | | | | |
Distributions to member | — | | | — | | | — | | | — | | | (10) | | | — | | | — | | | — | |
Contributions from parent/member | — | | | 19 | | | 103 | | | 237 | | | (299) | | | (144) | | | (45) | | | (110) | |
Transfer of cash, restricted cash, and cash equivalents to Constellation | 2,594 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Other financing activities | 3 | | | (1) | | | 1 | | | 1 | | | (8) | | | (9) | | | — | | | 2 | |
(Decrease) increase in cash flows from financing activities | $ | (36) | | | $ | 32 | | | $ | (56) | | | $ | (51) | | | $ | (544) | | | $ | (433) | | | $ | (12) | | | $ | (66) | |
Significant financing cash flow impacts for the Registrants for the three months ended March 31, 2023 and 2022 were as follows:
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
Exelon | $ | 701 |
| | $ | 1,251 |
|
Generation | (297 | ) | | (501 | ) |
ComEd | 812 |
| | 147 |
|
PECO | 121 |
| | 77 |
|
BGE | (112 | ) | | 286 |
|
Pepco | 199 |
| | 28 |
|
DPL | (42 | ) | | (14 | ) |
ACE | (13 | ) | | 74 |
|
|
| | | | | | | | | | | | |
| Successor | | | Predecessor |
| Nine Months Ended September 30, 2017 | | March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | $ | 161 |
| | $ | 65 |
| | | $ | 372 |
|
Debt
•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. See Note 1110 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further detailsadditional information on short-term borrowings for the Registrants.
•Long-term debt, net, varies due to debt issuances and redemptions each year. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
•Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 — Commitments and Contingenciesof the 2022 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
•Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation.
Debt
See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
Dividends
Cash dividend payments and distributions duringDuring the ninethree months ended September 30, 2017 and 2016 by Registrant were as follows:March 31, 2023, the following long-term debt was retired and/or redeemed:
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Company | | Type | | Interest Rate | | | Maturity | | Amount |
Exelon | | SMBC Term Loan Agreement | | SOFR plus 0.65% | | | July 21, 2023 | | $ | 300 | |
Exelon | | US Bank Term Loan Agreement | | SOFR plus 0.65% | | | July 21, 2023 | | 300 | |
| | | | | | | | | |
Exelon | | PNC Term Loan Agreement | | SOFR plus 0.65% | | | July 24, 2023 | | 250 | |
Exelon | | Long-Term Software License Agreement | | 3.70 | % | | | August 9, 2025 | | 6 | |
Exelon | | Long-Term Software License Agreement | | 3.70 | % | | | August 9, 2025 | | 1 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
Exelon | $ | 921 |
| | $ | 873 |
|
Generation | 494 |
| | 167 |
|
ComEd | 316 |
| | 275 |
|
PECO | 216 |
| | 208 |
|
BGE(a) | 148 |
| | 142 |
|
Pepco | 133 |
| | 92 |
|
DPL | 82 |
| | 39 |
|
ACE | 53 |
| | 24 |
|
129
|
| | | | | | | | | | | | |
| Successor | | | Predecessor |
| Nine Months Ended September 30, 2017 |
| March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | $ | 267 |
| | $ | 174 |
| | | $ | — |
|
_________
| |
(a) | Includes dividends paid on BGE’s preference stock in 2016. |
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the ninethree months ended September 30, 2017March 31, 2023 and for the fourthsecond quarter of 20172023 were as follows:
|
| | | | | | | | | | |
Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) |
First Quarter 2017 | | January 31, 2017 | | February 15, 2017 | | March 10, 2017 | | $ | 0.3275 |
|
Second Quarter 2017 | | April 25, 2017 | | May 15, 2017 | | June 9, 2017 | | $ | 0.3275 |
|
Third Quarter 2017 | | July 25, 2017 | | August 15, 2017 | | September 8, 2017 | | $ | 0.3275 |
|
Fourth Quarter 2017 | | September 25, 2017 | | November 15, 2017 | | December 8, 2017 | | $ | 0.3275 |
|
_________
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(a)Period | Exelon's Board | Declaration Date | | Shareholder of Directors approved a revised dividend policy. The approved policy will raise the dividend 2.5% each year for the next three years, beginning with the Record Date | | Dividend Payable Date | | Cash per Share(a) |
First Quarter 2023 | | February 14, 2023 | | February 27, 2023 | | March 10, 2023 | | $ | 0.3600 | |
Second Quarter 2023 | | April 25, 2023 | | May 15, 2023 | | June 2016 dividend and subject to Board approval.9, 2023 | | $ | 0.3600 | |
Short-Term Borrowings
Short-term borrowings incurred (repaid) during the nine months ended September 30, 2017 and 2016 by Registrant were as follows:
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
Exelon | $ | (559 | ) | | $ | (1,271 | ) |
Generation | (609 | ) | | 43 |
|
ComEd | — |
| | (284 | ) |
BGE | (45 | ) | | (210 | ) |
Pepco | (23 | ) | | (64 | ) |
DPL | 54 |
| | (88 | ) |
ACE | 65 |
| | (5 | ) |
|
| | | | | | | | | | | | |
| Successor | | | Predecessor |
| Nine Months Ended September 30, 2017 |
| March 24, 2016 to September 30, 2016 | |
| January 1, 2016 to March 23, 2016 |
PHI | $ | (404 | ) | | $ | (820 | ) | | | $ | 379 |
|
Contributions from Parent/Member
Contributions received from Parent/Member for the nine months ended September 30, 2017 and 2016 by Registrant were as follows:
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
Generation | $ | 102 |
| | $ | 142 |
|
ComEd (a)(b) | 567 |
| | 188 |
|
PECO (b) | 16 |
| | 18 |
|
BGE (b) | 77 |
| | 28 |
|
Pepco (c) | 161 |
| | 187 |
|
DPL (c) | — |
| | 113 |
|
ACE (c) | — |
| | 139 |
|
|
| | | | | | | | | | | | |
| Successor | | | Predecessor |
| Nine Months Ended September 30, 2017 | | March 24, 2016 to September 30, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI (b) | $ | 758 |
| | $ | 1,088 |
| | | $ | — |
|
_________
| | | | | | | | |
(a) | Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernization pursuant to EIMA and transmission upgrades. |
| | | | | | |
(b) | Contribution paid by Exelon. |
| | | | | | |
(c) | Contribution paid by PHI. | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Other
For the nine months ended September 30, 2017, other financing activities primarily consist__________
(a)Exelon's Board of debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial StatementsDirectors approved an updated dividend policy for further details of the Registrants’ debt issuances.2023. The 2023 quarterly dividend will be $0.36 per share.
Credit Matters and Cash Requirements
The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $9.5$4.0 billion in aggregate total commitments of which $8.3$3.2 billion was available to support additional commercial paper as of September 30, 2017,March 31, 2023, and of which no financial institution has more than 7%6% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper marketmarkets and had availability under their revolving credit facilities during the third quarter of 2017three months ended March 31, 2023 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon 20162022 Form 10-K for furtheradditional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flowflows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity. If Generation lostliquidity to support the estimated future cash requirements.
On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its investment grade credit rating ascommon stock, having an aggregate gross sales price of September 30, 2017, it would have been requiredup to provide incremental collateral$1.0 billion. Exelon has no obligation to offer or sell any shares of $1.8 billion to meet collateral obligations for derivatives, non-derivatives, normal purchase normalcommon stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales contractsunder the Equity Distribution Agreement. As of March 31, 2023, Exelon has not issued any shares of common stock under the ATM program and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within its current available credit facility capacities of $4.6 billion.
has not entered into any forward sale agreements.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at September 30, 2017March 31, 2023 and available credit facility capacity prior to any incremental collateral at September 30, 2017:March 31, 2023:
| | | | | | | | | | | | | | | | | |
| PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral |
ComEd | $ | 17 | | | $ | — | | | $ | 586 | |
PECO | 1 | | | 39 | | | 455 | |
BGE | 3 | | | 73 | | | 357 | |
| | | | | |
Pepco | 4 | | | — | | | 300 | |
DPL | 4 | | | 14 | | | 300 | |
ACE | 2 | | | — | | | 300 | |
__________
(a)Represents incremental collateral related to natural gas procurement contracts.
|
| | | | | | | | | | | |
| PJM Credit Policy Collateral | | Other Incremental Collateral Required (a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral |
ComEd | $ | 18 |
| | $ | — |
| | $ | 998 |
|
PECO | 3 |
| | 20 |
| | 599 |
|
BGE | 3 |
| | 28 |
| | 600 |
|
Pepco | 4 |
| | — |
| | 300 |
|
DPL | 1 |
| | 9 |
| | 300 |
|
ACE | — |
| | — |
| | 300 |
|
Capital Expenditure Spending_________As of March 31, 2023, the most recent estimates of capital expenditures for plant additions and improvements for 2023 are as follows:
| |
(a) | Represents incremental collateral related to natural gas procurement contracts. |
| | | | | | | | | | | | | | | | | | | | | | | |
(In millions) | Transmission | | Distribution | | Gas | | Total(a) |
Exelon | N/A | | N/A | | N/A | | $ | 7,175 | |
ComEd | 500 | | | 2,075 | | | N/A | | 2,550 | |
PECO | 75 | | | 975 | | | 325 | | | 1,375 | |
BGE | 325 | | | 525 | | | 475 | | | 1,325 | |
PHI | 550 | | | 1,225 | | | 125 | | | 1,900 | |
Pepco | 250 | | | 650 | | | N/A | | 900 | |
DPL | 175 | | | 275 | | | 125 | | | 575 | |
ACE | 125 | | | 300 | | | N/A | | 425 | |
__________
(a)Numbers rounded to the nearest $25M and may not sum due to rounding.
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Retirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $20 million in 2023. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2022 Form 10-K for additional information on pension and OPEB contributions.
Credit Facilities
Exelon Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes.Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet theirmeets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective
credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
The following table reflectsSee Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at September 30, 2017:
Commercial Paper Programs
|
| | | | | | | | | | | |
Commercial Paper Issuer | | Maximum Program Size (a)(b) | | Outstanding Commercial Paper at September 30, 2017 | | Average Interest Rate on Commercial Paper Borrowings for the Nine Months Ended September 30, 2017 |
Exelon Corporate | | $ | 600 |
| | $ | — |
| | 1.16 | % |
Generation | | 5,300 |
| | — |
| | 1.20 | % |
ComEd | | 1,000 |
| | — |
| | 1.24 | % |
PECO | | 600 |
| | — |
| | 1.13 | % |
BGE | | 600 |
| | — |
| | 1.15 | % |
Pepco | | 500 |
| | — |
| | 1.04 | % |
DPL | | 500 |
| | 54 |
| | 1.40 | % |
ACE | | 350 |
| | 65 |
| | 1.36 | % |
_________
| |
(a) | Excludes $525 million bilateral credit facilities that do not back Generation's commercial paper program. |
| |
(b) | Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of September 30, 2017, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $5 million, $12 million, $21 million and $2 million, respectively. |
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility. At September 30, 2017, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:short term borrowing activity.
Credit Agreements
|
| | | | | | | | | | | | | | | | | | | | | | |
Borrower | | Facility Type | | Aggregate Bank Commitment(a)(b)(c) | | Facility Draws | | Outstanding Letters of Credit | | Available Capacity at September 30, 2017 |
Actual | | To Support Additional Commercial Paper(b)(d) |
Exelon Corporate | | Syndicated Revolver | | $ | 600 |
| | $ | — |
| | $ | 45 |
| | $ | 555 |
| | $ | 555 |
|
Generation(e) | | Syndicated Revolver | | 5,300 |
| | — |
| | 887 |
| | 4,413 |
| | 4,413 |
|
Generation | | Bilaterals | | 525 |
| | 70 |
| | 235 |
| | 220 |
| | — |
|
ComEd | | Syndicated Revolver | | 1,000 |
| | — |
| | 2 |
| | 998 |
| | 998 |
|
PECO | | Syndicated Revolver | | 600 |
| | — |
| | 1 |
| | 599 |
| | 599 |
|
BGE | | Syndicated Revolver | | 600 |
| | — |
| | — |
| | 600 |
| | 600 |
|
Pepco | | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 300 |
|
DPL | | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 246 |
|
ACE | | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 235 |
|
_________
| |
(a) | Excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of September 30, 2017, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $5 million, $12 million, $21 million and $2 million, respectively. |
| |
(b) | Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility |
| |
(c) | Excludes nonrecourse debt letters of credit, see Note 14 — Debt and Credit Agreements in the Exelon 2016 Form 10-K for further information on Continental Wind nonrecourse debt. |
| |
(d) | Excludes $525 million bilateral credit facilities that do not back Generation’s commercial paper program. |
| |
(e) | Excludes ExGen Texas Power Financing's $20 million of borrowed debt on its revolving credit facility. |
As of September 30, 2017, there was $70 million of borrowings under Generation's bilateral credit facilities.
Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:
|
| | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
Prime based borrowings | 27.5 | | 27.5 | | 7.5 | | 0.0 | | 0.0 | | 7.5 |
| | 7.5 |
| | 7.5 |
|
LIBOR-based borrowings | 127.5 | | 127.5 | | 107.5 | | 90.0 | | 100.0 | | 107.5 |
| | 107.5 |
| | 107.5 |
|
The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 90 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.
Each revolving credit agreement for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the nine months ended September 30, 2017:
|
| | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
Credit agreement threshold | 2.50 to 1 | | 3.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 |
At September 30, 2017, the interest coverage ratios at Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE were as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
Interest coverage ratio | 6.27 |
| | 9.02 |
| | 10.83 |
| | 8.26 |
| | 10.66 |
| | 6.83 | | 8.78 | | 6.03 |
An event of default under Exelon, Generation, ComEd, PECO or BGE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $50 million in the aggregate will constitute an event of default under the credit facility.
The absence of a material adverse change in Exelon's or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for Exelon and the Utility Registrants did not change for the three months ended March 31, 2023.
Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pools.pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2017,March 31, 2023, are presented in the following table:table. Pepco, DPL, and ACE had no activity within the PHI intercompany money pool during the three months ended March 31, 2023.
|
| | | | | | | | | | | |
Exelon Intercompany Money Pool | | During the Three Months Ended September 30, 2017 | | As of September 30, 2017 |
Contributed (borrowed) | | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) |
Exelon Corporate | | $ | 579 |
| | n/a |
| | $ | 280 |
|
Generation | | — |
| | (417 | ) | | (146 | ) |
PECO | | 97 |
| | (10 | ) | | 57 |
|
BSC | | — |
| | (369 | ) | | (245 | ) |
PHI Corporate (a)
| | n/a |
| | (33 | ) | | (1 | ) |
PCI (a) | | 54 |
| | — |
| | 54 |
|
_________
| |
(a) | As a result of the merger, PHI Corporate and PCI began to participate in the Exelon Intercompany Money Pool effective March 24, 2016. |
|
| | | | | | | | | | | | |
PHI Intercompany Money Pool | | During the Three Months Ended September 30, 2017 | | As of September 30, 2017 |
Contributed (borrowed) | | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) |
PHI Corporate | | $ | 51 |
| | $ | (1 | ) | | $ | — |
|
PHISCO | | 24 |
| | (25 | ) | | — |
|
Investments in Nuclear Decommissioning Trust Funds
Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. Generation’s and CENG’s investment policies establish limits on the concentration of holdings in any one company and also in any one industry. See Note 13 —Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications. | | | | | | | | | | | | | | | | | | | | |
| | During the Three Months Ended March 31, 2023 | | As of March 31, 2023 |
Exelon Intercompany Money Pool | | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) |
Exelon Corporate | | $ | 510 | | | $ | — | | | $ | 266 | |
PECO | | — | | | (238) | | | — | |
BSC | | — | | | (327) | | | (259) | |
PHI Corporate | | — | | | (52) | | | (52) | |
PCI | | 45 | | | — | | | 45 | |
Shelf Registration Statements
Exelon Generation, ComEd, PECO, BGE, Pepco, DPL and ACEthe Utility Registrants have a currently effective combined shelf registration statement, unlimited in amount, filed with the SEC, that will expire in August 2019.2025. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.
Regulatory Authorizations
Generation, ComEd, PECO, BGE, Pepco, DPL and ACEThe Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of March 31, 2023 |
| | Short-term Financing Authority | | Remaining Long-term Financing Authority |
Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount |
ComEd | | FERC | | December 31, 2023 | | $ | 2,500 | | | ICC | | January 1, 2025 | | $ | 368 | |
PECO | | FERC | | December 31, 2023 | | 1,500 | | | PAPUC | | December 31, 2024 | | 1,125 | |
BGE(a) | | FERC | | December 31, 2023 | | 700 | | | MDPSC | | N/A | | 1,800 | |
Pepco(b) | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DCPSC | | December 31, 2025 | | 1,150 | |
DPL(b) | | FERC | | December 31, 2023 | | 500 | | | MDPSC / DEPSC | | December 31, 2025 | | 1,075 | |
ACE | | NJBPU | | December 31, 2023 | | 350 | | | NJBPU | | December 31, 2024 | | 625 | |
__________
(a)On December 21, 2022, BGE received approval from the MDPSC for $1.8 billion in new long-term financing authority with an effective date of January 4, 2023.
(b)The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DEPSC has an expiration date of December 31, 2025.
|
| | | | | | | | | | | | | | | | |
| | Short-term Financing Authority(a)(b) | | Long-term Financing Authority(c) |
Commission | | Expiration Date | | Amount (in millions) | Commission | | Expiration Date | | Amount (in millions) |
ComEd(d) | | FERC | | December 31, 2017 | | $ | 2,500 |
| | ICC | | 2019 | | $ | 1,383 |
|
PECO | | FERC | | December 31, 2017 | | 1,500 |
| | PAPUC | | December 31, 2018 | | 1,275 |
|
BGE | | FERC | | December 31, 2017 | | 700 |
| | MDPSC | | N/A | | 700 |
|
Pepco | | FERC | | June 30, 2018 | | 500 |
| | MDPSC / DCPSC | | September 25, 2017 | | — |
|
DPL | | FERC | | June 30, 2018 | | 500 |
| | MDPSC / DPSC | | December 31, 2017 | | 125 |
|
ACE | | NJPU | | January 1, 2018 | | 350 |
| | NJBPU | | December 31, 2017 | | 300 |
|
_________
| |
(a) | Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority. |
| |
(b) | On October 31, 2017, ComEd, PECO, BGE, Pepco and DPL filed applications with FERC for renewal of their short-term financing authority through December 31, 2019. ComEd, PECO, BGE, Pepco and DPL expect approval of the applications before the end of the year. |
| |
(c) | Pepco, DPL, and ACE, are currently in the process renewing their long-term financing authority with their respective commissions and expect approvals before the end of the year. |
| |
(d) | ComEd had $1,140 million available in long-term debt refinancing authority and $243 million available in new money long term debt financing authority from the ICC as of September 30, 2017 and has an expiration date of June 1, 2019 and March 1, 2019, respectively. |
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK Contractual ObligationsThe Registrants hold commodity and Off-Balance Sheet Arrangements
Contractual obligations represent cash obligationsfinancial instruments that are consideredexposed to the following market risks:
•Commodity price risk, which is discussed further below.
•Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be firm commitments and commercial commitments triggeredshared by future events.the remaining participants. See Note 249 — Commitments and Contingencies of the Combined Notes to ConsolidatedDerivative Financial Statements in the Exelon 2016 Form 10-K.
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Basis of PresentationInstruments of the Combined Notes to Consolidated Financial Statements for further information.
For an in-deptha detailed discussion of counterparty credit risk related to derivative instruments.
•Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 8 — Retirement Benefits of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 20162022 Form 10-K for additional information.
•Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and "Management's Discussionvariable-rate debt to manage interest rate exposure. See Note 10 — Debt and AnalysisCredit Agreements of the Combined Notes to Consolidated Financial ConditionStatements for additional information. In addition, Exelon may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges, or to lock in rate levels on borrowings, which are typically designated as economic hedges. See Note 9 – Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
•Electric operating revenues risk associated with ComEd's distribution formula rate. ComEd's ROE for its electric distribution service through 2023 is directly correlated to yields on U.S. Treasury bonds. Exelon Corporate may utilize interest rate derivatives to mitigate volatility and Resultsmanage risk to Exelon, which are typically accounted for as economic hedges. See Note 9 – Derivative Financial Instruments of Operations - Contractual Obligations and Commercial Commitments."
Item 3. Quantitative and Qualitative Disclosures about Market Riskthe Combined Notes to Consolidated Financial Statements for additional information.
The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are exposedutilized to marketreduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.
Exelon manages these risks associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon’s RMC approvesthrough risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired byRisk management issues are reported to Exelon’s Executive Committee, the chief executive officerRisk Management Committees of each Utility Registrant, and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the FinanceAudit and Risk Committee of the ExelonExelon’s Board of Directors on the scope of the risk management activities. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of Exelon’s 2016 Annual Report on Form 10-K incorporated herein by reference.Directors.
Commodity Price Risk (All Registrants)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon generatespurchases differs from the amount of energy it has contracted to sell, Exelon has price risk fromis exposed to market fluctuations in commodity price movements.prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity fossil fuel and other commodities.
Generation
Normal Operations and Hedging Activities.Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including forwards, futures, swaps and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2017 through 2019.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Exelon's hedging program involves the hedging of commodity risk for Exelon's expected generation, typically on a ratable basis over a three-year period. As of September 30, 2017, the percentage of expected generation hedged is 98%-101%, 79%-82% and 45%-48% for 2017, 2018 and 2019, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to the Utility Registrants to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire non-proprietary trading portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on September 30, 2017 market conditions and hedged position would be an increase in pre-tax net income of approximately $10 million for 2017 and decreases of approximately $170 million and $500 million, respectively, for 2018and 2019. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.
Proprietary Trading Activities.Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss and Value-at-Risk (VaR) limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities, which included physical volumes of 2,601 GWhs and 6,763 GWhs for the three and nine months ended September 30, 2017, respectively, and 1,506 GWhs and 4,015 GWhs and for the three and nine months September 30, 2016, respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. Proprietary trading portfolio activity for the nine months ended September 30, 2017 resulted in $11 million of pre-tax gains due to net mark-to-market gains of $3 million and realized gains of $8 million. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period and a one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $0.1 million of exposure during the quarter. Generation has not segregated proprietary trading activity within the following discussion because of the relative size of the proprietary trading portfolio in comparison to Generation’s total Revenue net of purchase power and fuel expense for the nine months ended September 30, 2017 of $6,526 million.
Fuel Procurement.Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 60% of Generation’s uranium concentrate requirements
from 2017 through 2021 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.
ComEdgas.
ComEd entered into 20-year contracts forfloating-to-fixed renewable energy and RECsswap contracts beginning in June 2012.2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd is permitted to recover its renewablehas block energy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014. See Note 5 — Regulatory Matters and Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives. ComEd does not enter into derivatives for speculative or proprietary trading purposes.
PECO
PECO has contracts to procure electric supply that wereare executed through thea competitive procurement process, outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO has certain full requirements contracts which are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance,NPNS, and as a result are accounted for on an accrual basis of accounting. Under the DSP Programs, PECO, is permittedBGE, Pepco, DPL, and ACE have contracts to recover itsprocure electric supply that are executed through a competitive procurement costs from retail customers with no mark-up.
process. PECO, has also entered into derivative natural gas contracts, which either qualify for the normal purchasesBGE, Pepco, DPL, and normal sales exception orACE have no mark-to-market balances because the derivatives are index priced, to hedge its long-term price risk in the natural gas market. PECO’s hedging program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.
PECO does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
BGE
BGE procures electric supply for default service customers throughcertain full requirements contracts, pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts thatwhich are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance,NPNS, and as a result are accounted for on an accrual basis of accounting. Under the SOS program,Other full requirements contracts are not derivatives.
PECO, BGE, is permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return component and an incremental cost component.
BGE hasDPL also entered intohave executed derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception,NPNS, to hedge itstheir long-term price risk in the natural gas market. The hedging programprograms for natural gas procurement hashave no direct impact on BGE’stheir financial position. However, under BGE’s market-based rates incentive mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers.statements.
BGE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 109 — Derivative Financial Instruments and Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.
Pepco
Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco's wholesale power supply costs and
include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.
Pepco does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
DPL
DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL's wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative costs. DPL locks in fixed prices for all of its SOS requirements through full requirements contracts. DPL’s price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
DPL provides natural gas to its customers under a GCR mechanism approved by the DPSC. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas.
DPL does not enter into derivatives for speculative or proprietary trading purposes. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.
ACE
ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE's wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.
ACE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
Trading and Non-Trading Marketing Activities. The following detailed presentation of Exelon’s, Generation’s, ComEd’s, PHI's and DPL's trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).
The following table provides detail on changes in Exelon’s, Generation’s, ComEd’s, PHI's and DPL's commodity mark-to-market net asset or liability balance sheet position from December 31, 2016 to September 30, 2017. It indicatespresents the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all normal purchase and normal sales contracts and does not segregate proprietary trading activity. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2017 and December 31, 2016.
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| | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI | | DPL |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016(a) | $ | 719 |
| | $ | 977 |
| | $ | (258 | ) | | $ | — |
| | $ | — |
|
Total change in fair value during 2017 of contracts recorded in results of operations | (13 | ) | | (13 | ) | | — |
| | — |
| | — |
|
Reclassification to realized of contracts recorded in results of operations | (138 | ) | | (138 | ) | | — |
| | — |
| | — |
|
Contracts received at acquisition date | — |
| | — |
| | — |
| | — |
| | — |
|
Changes in fair value — recorded through regulatory assets and liabilities(b) | (21 | ) | | — |
| | (19 | ) | | (2 | ) | | (2 | ) |
Changes in allocated collateral | 88 |
| | 86 |
| | — |
| | 2 |
| | 2 |
|
Changes in net option premium paid/(received) | (35 | ) | | (35 | ) | | — |
| | — |
| | — |
|
Option premium amortization | (15 | ) | | (15 | ) | | — |
| | — |
| | — |
|
Upfront payments and amortizations(c) | (54 | ) | | (54 | ) | | — |
| | — |
| | — |
|
Total mark-to-market energy contract net assets (liabilities) at September 30, 2017(a) | $ | 531 |
| | $ | 808 |
| | $ | (277 | ) | | $ | — |
| | $ | — |
|
_________
| |
(a) | Amounts are shown net of collateral paid to and received from counterparties. |
| |
(b) | For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of September 30, 2017, ComEd recorded a regulatory liability of $277 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the nine months ended September 30, 2017, ComEd also recorded $32 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers. |
| |
(c) | Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortization. |
Fair Values. The following tables present maturity and source of fair value for Exelon, GenerationExelon’s and ComEdComEd’s mark-to-market commodity contract net assets (liabilities).liabilities. These net liabilities are associated with ComEd’s floating-to-fixed energy swap contracts with unaffiliated suppliers. The tables providetable provides two fundamental pieces of information. First, the tables providetable provides the source of fair value used in determining the carrying amount of the Registrants’Exelon's and ComEd's total mark-to-market net assets (liabilities), net of allocated collateral.liabilities. Second, the tables showtable shows the maturity, by year, of the Registrants’Exelon's and ComEd's commodity contract net assets (liabilities), net of allocated collateral,liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 911 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Exelon
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| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Total Fair Value |
| 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | |
Actively quoted prices (Level 1) | $ | 27 |
| | $ | 1 |
| | $ | (29 | ) | | $ | (13 | ) | | $ | 2 |
| | $ | (2 | ) | | $ | (14 | ) |
Prices provided by external sources (Level 2) | 112 |
| | 109 |
| | 7 |
| | (6 | ) | | 5 |
| | — |
| | 227 |
|
Prices based on model or other valuation methods (Level 3)(c) | 47 |
| | 339 |
| | 111 |
| | 18 |
| | (32 | ) | | (165 | ) | | 318 |
|
Total | $ | 186 |
| | $ | 449 |
| | $ | 89 |
| | $ | (1 | ) | | $ | (25 | ) | | $ | (167 | ) | | $ | 531 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Total Fair Value |
Commodity derivative contracts(a): | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | 2028 and Beyond | |
Prices based on model or other valuation methods (Level 3) | $ | (20) | | | $ | (16) | | | $ | (14) | | | $ | (12) | | | $ | (10) | | | $ | (26) | | | $ | (98) | |
_________
| |
(a) | Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations. |
| |
(b) | Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $415 million at September 30, 2017. |
| |
(c) | Includes ComEd’s(a)Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Generation
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| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Total Fair Value |
| 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | |
Actively quoted prices (Level 1) | $ | 27 |
| | $ | 1 |
| | $ | (29 | ) | | $ | (13 | ) | | $ | 2 |
| | $ | (2 | ) | | $ | (14 | ) |
Prices provided by external sources (Level 2) | 112 |
| | 109 |
| | 7 |
| | (6 | ) | | 5 |
| | — |
| | 227 |
|
Prices based on model or other valuation methods (Level 3) | 53 |
| | 360 |
| | 133 |
| | 40 |
| | (11 | ) | | 20 |
| | 595 |
|
Total | $ | 192 |
| | $ | 470 |
| | $ | 111 |
| | $ | 21 |
| | $ | (4 | ) | | $ | 18 |
| | $ | 808 |
|
_________
| |
(a) | Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations. |
| |
(b) | Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $415 million at September 30, 2017. |
ComEd
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| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Total Fair Value |
| 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 and Beyond | |
Commodity derivative contracts(a): | | | | | | | | | | | | | |
Prices based on model or other valuation methods (Level 3) | $ | (6 | ) | | $ | (21 | ) | | $ | (22 | ) | | $ | (22 | ) | | $ | (21 | ) | | $ | (185 | ) | | $ | (277 | ) |
_________
| |
(a) | Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Credit Risk, Collateral and Contingent Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk, collateral and contingent related features.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2017. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $18 million, $22 million, $22 million, $34 million, $12 million, and $7 million as of September 30, 2017, respectively.
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| | | | | | | | | | | | | | | | | | | |
Rating as of September 30, 2017 | | Total Exposure Before Credit Collateral | | Credit Collateral(a) | | Net Exposure | | Number of Counterparties Greater than 10% of Net Exposure | | Net Exposure of Counterparties Greater than 10% of Net Exposure |
Investment grade | | $ | 828 |
| | $ | 9 |
| | $ | 819 |
| | 1 |
| | $ | 278 |
|
Non-investment grade | | 44 |
| | 4 |
| | 40 |
| |
|
| |
|
|
No external ratings | | | | | | | | | | |
Internally rated — investment grade | 316 |
| | — |
| | 316 |
| |
|
| |
|
|
Internally rated — non-investment grade | 100 |
| | 18 |
| | 82 |
| |
|
| |
|
|
Total | | $ | 1,288 |
| | $ | 31 |
| | $ | 1,257 |
| | 1 |
| | $ | 278 |
|
|
| | | | | | | | | | | | | | | |
| Maturity of Credit Risk Exposure |
Rating as of September 30, 2017 | Less than 2 Years | | 2-5 Years | | Exposure Greater than 5 Years | | Total Exposure Before Credit Collateral |
Investment grade | $ | 682 |
| | $ | 139 |
| | $ | 7 |
| | $ | 828 |
|
Non-investment grade | 36 |
| | 8 |
| | — |
| | 44 |
|
No external ratings | | | | | | | |
Internally rated — investment grade | 249 |
| | 35 |
| | 32 |
| | 316 |
|
Internally rated — non-investment grade | 87 |
| | 13 |
| | — |
| | 100 |
|
Total | $ | 1,054 |
| | $ | 195 |
| | $ | 39 |
| | $ | 1,288 |
|
|
| | | |
Net Credit Exposure by Type of Counterparty | As of September 30, 2017 |
Financial institutions | $ | 48 |
|
Investor-owned utilities, marketers, power producers | 538 |
|
Energy cooperatives and municipalities | 525 |
|
Other | 146 |
|
Total | $ | 1,257 |
|
_________
| |
(a) | As of September 30, 2017, credit collateral held from counterparties where Generation had credit exposure included $19 million of cash and $12 million of letters of credit. |
ComEd, PECO, BGE, PHI, Pepco, DPL and ACE
There have been no significant changes or additions to ComEd’s, PECO's, BGE's, PHI's, Pepco's, DPL's or ACE's exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 2016 Annual Report on Form 10-K.
See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.
Collateral (All Registrants)
Generation
As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas and other commodities. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the floating-to-fixed energy swap contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding collateral requirements.unaffiliated suppliers.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. In order to post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.
As of September 30, 2017, Generation had cash collateral of $460 million posted and cash collateral held of $49 million for external counterparties with derivative positions, of which $415 million amount in net cash collateral deposits and $1 million amount in net cash collateral receipts were offset against energy derivative and interest rate and foreign exchange derivative related to underlying energy contracts, respectively. As of September 30, 2017, $3 million of cash collateral held was not offset against net derivative positions because it was not associated with energy-related derivatives or as of the balance sheet date there were no positions to offset. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.
ComEd
As of September 30, 2017, ComEd held $10 million in collateral from suppliers in association with energy procurement contracts and held approximately $21 million in the form of cash and letters of credit for both annual and long-term renewable energy contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements in this report and Note 3 — Regulatory Matters of the 2016 Exelon Form 10-K for additional information.
PECO
As of September 30, 2017, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
BGE
BGE is not required to post collateral under its electric supply contracts nor was it holding collateral under its electric supply procurement contracts as of September 30, 2017. As of September 30, 2017, BGE was not required to post collateral under its natural gas procurement contracts but was holding an immaterial amount of collateral under its natural gas procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Pepco
Pepco is not required to post collateral under its energy procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
DPL
DPL is not required to post collateral under its energy procurement contracts. As of September 30, 2017, DPL was not required to post collateral under its natural gas procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
ACE
ACE is not required to post collateral under its energy procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
RTOs and ISOs (All Registrants)
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE participate in all, or some, of the established wholesale spot energy markets that are administered by PJM, ISO-NE, ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there are no spot energy markets, electricity is purchased and sold solely through bilateral agreements. For sales into the spot energy markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.
Exchange Traded Transactions (Exelon, Generation, PHI and DPL)
Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX and the Nodal exchange ("the Exchanges"). DPL enters into commodity transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on the Exchanges are significantly collateralized and have limited counterparty credit risk.
Interest Rate and Foreign Exchange Risk (All Registrants)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At September 30, 2017, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $491 million of notional amounts of floating-to-fixed hedges outstanding. Assuming the interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $4 million decrease in Exelon Consolidated pre-tax income for the nine months ended September 30, 2017. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges.
Equity Price Risk (Exelon and Generation)
Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of September 30, 2017, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy.
A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $626 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See ITEM 2. MANAGEMENT'S DISCUSSION4. CONTROLS AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of equity price risk as a result of the current capital and credit market conditions.
Item 4. Controls and ProceduresPROCEDURES
During the thirdfirst quarter of 2017,2023, each of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE'sthe Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by allthe Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’sthat Registrant's management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of September 30, 2017,March 31, 2023, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACEthe Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. AllThe Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There have beenwere no changes in internal control over financial reporting that occurred during the thirdfirst quarter of 20172023 that have materially affected, or are reasonably likely to materially affect, any of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’sthe Registrants' internal control over financial reporting.
PART II — OTHER INFORMATION
ItemITEM 1. Legal ProceedingsLEGAL PROCEEDINGS
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 2016the 2022 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2022 Form 10-K, and (b)(c) Notes 53 —Regulatory Matters and 1812 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
ITEM 1A. Risk FactorsRISK FACTORS
Risks Related to ExelonAll Registrants
At September 30, 2017,March 31, 2023, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 20162022 Form 10-K in ITEM 1A. RISK FACTORS.
Item 4. Mine Safety DisclosuresITEM 5. OTHER INFORMATION
All Registrants
Not applicable to the Registrants.None.
ItemITEM 6. ExhibitsEXHIBITS
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrantRegistrant and its subsidiaries on a consolidated basis and the relevant registrantRegistrant agrees to furnish a copy of any such instrument to the Commission upon request.
(4) Instruments Defining the Rights of Securities Holders, Including Indentures | | | | | | | | | | | | | | | | | |
Exelon Corporation | | | | |
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Potomac Electric Power Company | | | | |
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Delmarva Power & Light Company | | | | |
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101.INSAtlantic City Electric Company | XBRL Instance | | | |
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101.SCHExhibit No. | XBRL Taxonomy Extension SchemaDescription | | | |
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101.CALSupplemental Indenture to the Atlantic City Electric Company Mortgage and Deed of Trust, dated as of March 1, 2023 | XBRL Taxonomy Extension Calculation |
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101.DEF | XBRL Taxonomy Extension Definition |
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101.LAB | XBRL Taxonomy Extension Labels |
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101.PRE | XBRL Taxonomy Extension Presentation |
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017March 31, 2023 filed by the following officers for the following companies:
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Commonwealth Edison Company |
Exhibit No. | Description |
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PECO Energy Company |
Exhibit No. | Description |
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Baltimore Gas and Electric Company |
Exhibit No. | Description |
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Pepco Holdings LLC |
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Potomac Electric Power Company |
Exhibit No. | Description |
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Delmarva Power & Light Company |
Exhibit No. | Description |
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Atlantic City Electric Company |
Exhibit No. | Description |
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Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley(Sarbanes-Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017March 31, 2023 filed by the following officers for the following companies:
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Exelon Corporation |
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Commonwealth Edison Company |
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PECO Energy Company |
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Baltimore Gas and Electric Company |
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Pepco Holdings LLC |
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Potomac Electric Power Company |
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Delmarva Power & Light Company |
Exhibit No. | Description |
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Atlantic City Electric Company |
Exhibit No. | Description |
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101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
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101.SCH | Inline XBRL Taxonomy Extension Schema Document |
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101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
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101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document |
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101.LAB | Inline XBRL Taxonomy Extension Labels Linkbase Document |
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101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
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104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
SIGNATURES
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON CORPORATION
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/s/ CHRISTOPHERCALVIN G. BUTLER, JR. | | /s/ JEANNE M. CRANE | | /s/ JONATHAN W. THAYER JONES |
ChristopherCalvin G. Butler, Jr. | | Jeanne M. Crane | | Jonathan W. ThayerJones |
President, and Chief Executive Officer (Principal Executive Officer) and Director
| | Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
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/s/ DUANE M. DESPARTE
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Duane M. DesParte | | |
Senior Vice President and Corporate Controller
(Principal Accounting Officer)
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November 2, 2017
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON GENERATION COMPANY, LLC
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/s/ KENNETH W. CORNEW JOSEPH R. TRPIK | | /s/ BRYAN P. WRIGHT
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Kenneth W. CornewJoseph R. Trpik | | Bryan P. Wright |
President and Chief Executive Officer
(Principal Executive Officer)
| | Senior Vice President and Chief Financial Officer (Principal Financial Officer)
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/s/ MATTHEW N. BAUER
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Matthew N. Bauer | | |
Vice President andCorporate Controller
(Principal Accounting Officer)
| | |
November 2, 2017
May 3, 2023
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
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/s/ ANNE R. PRAMAGGIORE GIL C. QUINIONES | | /s/ JOSEPH R. TRPIK, JR. ELISABETH J. GRAHAM |
Anne R. PramaggioreGil C. Quiniones | | Joseph R. Trpik, Jr.Elisabeth J. Graham |
President and Chief Executive Officer
(Principal Executive Officer) and Director | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
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/s/ GERALDSTEVEN J. KOZEL CICHOCKI | | |
GeraldSteven J. KozelCichocki | | |
Vice President and Controller
Director, Accounting (Principal Accounting Officer) | | |
November 2, 2017
May 3, 2023
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PECO ENERGY COMPANY
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/s/ CRAIG L. ADAMS MICHAEL A. INNOCENZO | | /s/ PHILLIP S. BARNETT MARISSA HUMPHREY |
Craig L. AdamsMichael A. Innocenzo | | Phillip S. BarnettMarissa Humphrey |
President, and Chief Executive Officer (Principal Executive Officer) and Director
| | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
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/s/ SCOTT A. BAILEY CAROLINE FULGINITI | | |
Scott A. BaileyCaroline Fulginiti | | |
Vice President and Controller
Director, Accounting (Principal Accounting Officer) | | |
November 2, 2017May 3, 2023
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
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/s/ CALVIN G. BUTLER, JR. CARIM V. KHOUZAMI | | /s/ DAVIDDAVID M. VAHOS VAHOS |
Calvin G. Butler, Jr.Carim V. Khouzami | | David M. Vahos |
President, Chief Executive Officer (Principal Executive Officer) and Director | | Senior Vice President, Chief Financial Officer and Treasurer (Principal (Principal Financial Officer) |
| | |
/s/ ANDREW W. HOLMES JASON T. JONES | | |
Andrew W. HolmesJason T. Jones | | |
Vice President and Controller
Director, Accounting (Principal Accounting Officer) | | |
November 2, 2017May 3, 2023
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PEPCO HOLDINGS LLC
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/s/ DAVID M. VELAZQUEZ J. TYLER ANTHONY | | /s/ DONNA J. KINZEL PHILLIP S. BARNETT |
David M. VelazquezJ. Tyler Anthony | | Donna J. KinzelPhillip S. Barnett |
President, and Chief Executive Officer (Principal Executive Officer) and Director | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
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/s/ ROBERT M. AIKEN JULIE E. GIESE | | |
Robert M. AikenJulie E. Giese | | |
Vice President and Controller
Director, Accounting (Principal Accounting Officer) | | |
November 2, 2017May 3, 2023
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
POTOMAC ELECTRIC POWER COMPANY
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/s/ J. TYLER ANTHONY | | /s/ PHILLIP S. BARNETT |
J. Tyler Anthony | | Phillip S. Barnett |
President, Chief Executive Officer (Principal Executive Officer) and Director | | Senior Vice President, Chief Financial Officer, Treasurer (Principal Financial Officer) and Director |
| | |
/s/ DAVID M. VELAZQUEZ JULIE E. GIESE | | /s/ DONNA J. KINZEL
|
David M. VelazquezJulie E. Giese | | Donna J. Kinzel |
President and Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
/s/ ROBERT M. AIKEN
| | |
Robert M. Aiken | | |
Vice President and Controller Director, Accounting (Principal Accounting Officer) | | |
November 2, 2017May 3, 2023
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DELMARVA POWER & LIGHT COMPANY
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/s/ DAVID M. VELAZQUEZ J. TYLER ANTHONY | | /s/ DONNA J. KINZEL PHILLIP S. BARNETT |
David M. VelazquezJ. Tyler Anthony | | Donna J. KinzelPhillip S. Barnett |
President, and Chief Executive Officer
(Principal Executive Officer) and Director | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
/s/ ROBERT M. AIKEN JULIE E. GIESE | | |
Robert M. AikenJulie E. Giese | | |
Vice President and Controller Director, Accounting (Principal Accounting Officer) | | |
November 2, 2017May 3, 2023
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
ATLANTIC CITY ELECTRIC COMPANY
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/s/ DAVID M. VELAZQUEZ J. TYLER ANTHONY | | /s/ DONNA J. KINZEL PHILLIP S. BARNETT |
David M. VelazquezJ. Tyler Anthony | | Donna J. KinzelPhillip S. Barnett |
President, and Chief Executive Officer
(Principal Executive Officer) and Director | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer) |
| | |
/s/ ROBERT M. AIKEN JULIE E. GIESE | | |
Robert M. AikenJulie E. Giese | | |
Vice President and Controller Director, Accounting (Principal Accounting Officer) | | |
November 2, 2017
May 3, 2023