Document/ExhibitDescriptionPagesSize 1: 10-Q Quarterly Report HTML 4.24M
2: EX-4.1 Supplemental Indenture Between Dpl and the Bank of HTML 61K
New York Mellon
3: EX-31.1 Certification Filed by Christopher M. Crane for HTML 44K
Exelon Corporation
12: EX-31.10 Certification Filed by Phillip S. Barnett for HTML 44K
Pepco Holdings LLC
13: EX-31.11 Certification Filed by J. Tyler Anthony for HTML 44K
Potomac Electric Power Company
14: EX-31.12 Certification Filed by Phillip S. Barnett for HTML 44K
Potomac Electric Power Company
15: EX-31.13 Certification Filed by J. Tyler Anthony for HTML 44K
Delmarva Power & Light Company
16: EX-31.14 Certification Filed by Phillip S. Barnett for HTML 44K
Delmarva Power & Light Company
17: EX-31.15 Certification Filed by J. Tyler Anthony for HTML 44K
Atlantic City Electric Company
18: EX-31.16 Certification Filed by Phillip S. Barnett for HTML 44K
Atlantic City Electric Company
4: EX-31.2 Certification Filed by Joseph Nigro for Exelon HTML 44K
Corporation
5: EX-31.3 Certification Filed by Gil C. Quiniones for HTML 44K
Commonwealth Edison Company
6: EX-31.4 Certification Filed by Elisabeth J. Graham for HTML 44K
Commonwealth Edison Company
7: EX-31.5 Certification Filed by Michael A. Innocenzo for HTML 44K
Peco Energy Company
8: EX-31.6 Certification Filed by Robert J. Stefani for Peco HTML 44K
Energy Company
9: EX-31.7 Certification Filed by Carim V. Khouzami for HTML 44K
Baltimore Gas and Electric Co
10: EX-31.8 Certification Filed by David M. Vahos for HTML 44K
Baltimore Gas and Electric Co
11: EX-31.9 Certification Filed by J. Tyler Anthony for Pepco HTML 44K
Holdings LLC
19: EX-32.1 Filed by Christopher M. Crane for Exelon HTML 40K
Corporation
28: EX-32.10 Filed by Phillip S. Barnett for Pepco Holdings LLC HTML 40K
29: EX-32.11 Filed by J. Tyler Anthony for Potomac Electric HTML 40K
Power Company
30: EX-32.12 Filed by Phillip S. Barnett for Potomac Electric HTML 40K
Power Company
31: EX-32.13 Filed by J. Tyler Anthony for Delmarva Power & HTML 40K
Light Company
32: EX-32.14 Filed by Phillip S. Barnett for Delmarva Power & HTML 40K
Light Company
33: EX-32.15 Filed by J. Tyler Anthony for Atlantic City HTML 40K
Electric Company
34: EX-32.16 Filed by Phillip S. Barnett for Atlantic City HTML 40K
Electric Company
20: EX-32.2 Filed by Joseph Nigro for Exelon Corporation HTML 40K
21: EX-32.3 Filed by Gil C. Quiniones for Commonwealth Edison HTML 40K
Company
22: EX-32.4 Filed by Elisabeth J. Graham for Commonwealth HTML 40K
Edison Company
23: EX-32.5 Filed by Michael A. Innocenzo for Peco Energy HTML 40K
Company
24: EX-32.6 Filed by Robert J. Stefani for Peco Energy Company HTML 40K
25: EX-32.7 Filed by Carim V. Khouzami for Baltimore Gas and HTML 40K
Electric Company
26: EX-32.8 Filed by David M. Vahos for Baltimore Gas and HTML 40K
Electric Company
27: EX-32.9 Filed by J. Tyler Anthony for Pepco Holdings LLC HTML 40K
40: R1 Cover Page HTML 138K
41: R2 Consolidated Statements of Operations and HTML 305K
Comprehensive Income (Unaudited)
42: R3 Consolidated Statements of Cash Flows (Unaudited) HTML 258K
43: R4 Consolidated Balance Sheets (Unaudited) HTML 414K
44: R5 Consolidated Statements of Changes in Shareholders HTML 150K
Equity (Unaudited)
45: R6 Significant Accounting Policies (All Registrants) HTML 62K
46: R7 Discontinued Operations (Exelon) HTML 128K
47: R8 Mergers, Acquisitions, and Dispositions (Exelon HTML 42K
and Generation)
48: R9 Regulatory Matters (All Registrants) HTML 123K
49: R10 Revenue from Contracts with Customers (All HTML 64K
Registrants)
50: R11 Segment Information (All Registrants) HTML 399K
51: R12 Accounts Receivable (All Registrants) HTML 178K
52: R13 Nuclear Decommissioning (Exelon and Generation) HTML 46K
53: R14 Income Taxes (All Registrants) HTML 145K
54: R15 Retirement Benefits (All Registrants) HTML 153K
55: R16 Derivative Financial Instruments (All Registrants) HTML 60K
56: R17 Debt and Credit Agreements (All Registrants) HTML 104K
57: R18 Fair Value of Financial Assets and Liabilities HTML 509K
(All Registrants)
58: R19 Commitments and Contingencies (All Registrants) HTML 229K
59: R20 Changes in Accumulated Other Comprehensive Income HTML 78K
(Exelon)
60: R21 Supplemental Financial Information (All HTML 354K
Registrants)
61: R22 Related Party Transactions (All Registrants) HTML 219K
62: R23 Planned Separation HTML 128K
63: R24 Significant Accounting Policies (Policies) HTML 62K
64: R25 Discontinued Operations (Tables) HTML 121K
65: R26 Regulatory Matters (Tables) HTML 117K
66: R27 Revenue from Contracts with Customers (Tables) HTML 58K
67: R28 Segment Information (Tables) HTML 398K
68: R29 Accounts Receivable (Tables) HTML 182K
69: R30 Income Taxes (Tables) HTML 139K
70: R31 Retirement Benefits (Tables) HTML 89K
71: R32 Debt and Credit Agreements (Tables) HTML 104K
72: R33 Fair Value of Financial Assets and Liabilities HTML 512K
(Tables)
73: R34 Commitments and Contingencies (Tables) HTML 200K
74: R35 Changes in Accumulated Other Comprehensive Income HTML 81K
(Tables)
75: R36 Supplemental Financial Information (Tables) HTML 353K
76: R37 Related Party Transactions (Tables) HTML 221K
77: R38 Significant Accounting Policies (Details) HTML 72K
78: R39 Discontinued Operations and Disposal Groups HTML 73K
(Details)
79: R40 Discontinued Operations and Disposal Groups HTML 108K
(Details) - Income Statement
80: R41 Discontinued Operations and Disposal Groups HTML 178K
(Details) - Balance Sheet
81: R42 Discontinued Operations and Disposal Groups HTML 73K
(Details) - Cash Flows
82: R43 Mergers, Acquisitions, and Dispositions - HTML 42K
Narrative (Details)
83: R44 Regulatory Matters - Narrative (Details) HTML 70K
84: R45 Regulatory Matters - Schedule of Completed Rate HTML 169K
Cases (Details)
85: R46 Regulatory Matters - Schedule of Pending Rate HTML 69K
Cases (Details)
86: R47 Regulatory Matters - Annual Electric Transmission HTML 62K
Fillings (Details)
87: R48 Regulatory Matters - Capitalized Ratemaking Amount HTML 58K
Not Recognized (Details)
88: R49 Revenue from Contracts with Customers - HTML 98K
Performance Obligations (Details)
89: R50 Segment Information - Narrative (Details) HTML 43K
90: R51 Segment Information - Reconciliation to HTML 236K
Consolidated Financial Statements (Details)
91: R52 Segment Information - Electric and Gas Revenue by HTML 248K
Customer Class (Details)
92: R53 Accounts Receivable - Allowance for Credit Losses HTML 99K
Rollforward (Details)
93: R54 Accounts Receivable - Unbilled Customer Revenue HTML 57K
(Details)
94: R55 Accounts Receivable - Purchases and Sales of HTML 60K
Accounts Receivable (Detail)
95: R56 Early Plant Retirements - Narrative (Details) HTML 42K
96: R57 Early Plant Retirements - Implications of HTML 46K
Potential Early Plant Retirement on Balance Sheet
(Details)
97: R58 Nuclear Decommissioning - Narrative (Details) HTML 42K
98: R59 Nuclear Decommissioning - Rollforward of Nuclear HTML 42K
Decommissioning ARO (Details)
99: R60 Asset Impairments - Narrative (Details) HTML 48K
100: R61 Income Taxes - Narrative (Details) HTML 63K
101: R62 Income Taxes - Reconciliation to Effective Tax HTML 107K
Rate (Details)
102: R63 Income Taxes - Unrecognized Tax Benefits (Details) HTML 48K
103: R64 Retirement Benefits - Narrative (Details) HTML 61K
104: R65 Retirement Benefits - Calculation of Net Periodic HTML 70K
Benefit Cost (Details)
105: R66 Retirement Benefits - Allocated Portion of Pension HTML 67K
and Postretirement Benefit Plan Costs (Details)
106: R67 Retirement Benefits - Defined Contribution Savings HTML 58K
Plans (Details)
107: R68 Derivative Financial Instruments - Narrative HTML 68K
(Details)
108: R69 Debt and Credit Agreements - Narrative (Details) HTML 64K
109: R70 Debt and Credit Agreements - Commercial Paper HTML 64K
Borrowings (Details)
110: R71 Summary of Revolving Credit Agreements (Details) HTML 67K
111: R72 Debt and Credit Agreements - Issuance of Long-Term HTML 82K
Debt (Details)
112: R73 Fair Value of Financial Assets and Liabilities - HTML 116K
Fair Value of Financial Liabilities Recorded at
Amortized Cost (Details)
113: R74 Fair Value of Financial Assets and Liabilities - HTML 348K
Fair Value Measurements of Assets and Liabilities,
Recurring and Nonrecurring (Details)
114: R75 Fair Value of Financial Assets and Liabilities - HTML 84K
Fair Value Assets Liabilities Measured On
Recurring Basis Unobservable Input Reconciliation
(Details)
115: R76 Fair Value of Financial Assets and Liabilities - HTML 46K
Fair Value Assets And Liabilities Measured On
Recurring Basis Gain Loss Included In Earnings
(Details)
116: R77 Fair Value of Financial Assets and Liabilities - HTML 69K
Fair Value Inputs Assets Quantitative Information
(Details)
117: R78 Commitments and Contingencies - Narrative HTML 91K
(Details)
118: R79 Commitments and Contingencies - Merger Commitment HTML 61K
(Details)
119: R80 Commitments and Contingencies - Schedule of HTML 154K
Commercial Commitments (Details)
120: R81 Commitments and Contingencies - Schedule of HTML 67K
Accruals for Environmental Matters (Details)
121: R82 Changes in Accumulated Other Comprehensive Income HTML 83K
- Schedule of Changes in AOCI (Details)
122: R83 Changes in Accumulated Other Comprehensive Income HTML 49K
- Income Taxes Allocated to Other Comprehensive
Income (Loss) Components (Details)
123: R84 Variable Interest Entities - Narrative (Details) HTML 41K
124: R85 Variable Interest Entities - Assets and HTML 146K
Liabilities of Consolidated VIES (Details)
125: R86 Variable Interest Entities - Summary of HTML 56K
Significant Unconsolidated VIEs (Details)
126: R87 Supplemental Financial Information - Operations HTML 62K
(Detail)
127: R88 Supplemental Financial Information - Taxes Other HTML 65K
Than Income Taxes (Details)
128: R89 Supplemental Financial Information - Cash Flow HTML 150K
(Details)
129: R90 Supplemental Financial Information - Balance Sheet HTML 106K
(Details)
130: R91 Related Party Transactions - Operating Revenues HTML 65K
and Purchased Power and Fuel (Details)
131: R92 Related Party Transactions - BSC and PHISCO HTML 79K
Service Companies (Details)
132: R93 Related Party Transactions - Current Receivables HTML 182K
From/Payables To Affiliates (Details)
133: R94 Related Party Transactions - Long Term Debt to HTML 60K
Financing Trusts (Details)
136: XML IDEA XML File -- Filing Summary XML 222K
134: XML XBRL Instance -- exc-20220331_htm XML 12.22M
135: EXCEL IDEA Workbook of Financial Reports XLSX 224K
36: EX-101.CAL XBRL Calculations -- exc-20220331_cal XML 243K
37: EX-101.DEF XBRL Definitions -- exc-20220331_def XML 2.38M
38: EX-101.LAB XBRL Labels -- exc-20220331_lab XML 3.28M
39: EX-101.PRE XBRL Presentations -- exc-20220331_pre XML 2.53M
35: EX-101.SCH XBRL Schema -- exc-20220331 XSD 365K
137: JSON XBRL Instance as JSON Data -- MetaLinks 710± 1.09M
138: ZIP XBRL Zipped Folder -- 0001109357-22-000059-xbrl Zip 977K
Accounting Implications of the Regulatory Agreements with ComEd and PECO
Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances on the balance sheet. For the purposes of making this determination, the decommissioning obligation referred
to is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.
For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, the offset of decommissioning-related activities within the Consolidated Statements of Operations and Comprehensive Income results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd
is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the second quarter of 2022, a pre-tax charge of $53 million was recorded in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being suspended. Generation believes that additional growth of the NDT funds for the Byron units will ultimately be sufficient to cover the future costs of decommissioning.
As of March 31, 2022, decommissioning-related activities for all of the former ComEd units, except for Byron (see discussion above) and Zion (see Note 10 – Asset Retirement
Obligations of the Exelon 2021 Form 10-K), are currently offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
See Note 10 – Asset Retirement Obligations of the Exelon 2021 Form 10-K for additional information, including the former PECO units.
Securities registered pursuant to Section 12(b) of the Act:
Title
of each class
Trading Symbol(s)
Name of each exchange on which registered
EXELON CORPORATION:
iCommon stock, without par value
iEXC
iThe
Nasdaq Stock Market LLC
PECO ENERGY COMPANY:
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% iCumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company
iEXC/28
iNew
York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. iYesx No o
Indicate by check mark
whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). iYesx No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions
of “large accelerated filer,”“accelerated filer,”“smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Exelon Corporation
iLarge
Accelerated Filer
x
Accelerated Filer
☐
Non-accelerated Filer
☐
Smaller Reporting Company
i☐
Emerging Growth Company
i☐
Commonwealth
Edison Company
Large Accelerated Filer
☐
Accelerated Filer
☐
iNon-accelerated Filer
x
Smaller Reporting Company
i☐
Emerging
Growth Company
i☐
PECO Energy Company
Large Accelerated Filer
☐
Accelerated Filer
☐
iNon-accelerated
Filer
x
Smaller Reporting Company
i☐
Emerging Growth Company
i☐
Baltimore
Gas and Electric Company
Large Accelerated Filer
☐
Accelerated Filer
☐
iNon-accelerated Filer
x
Smaller Reporting Company
i☐
Emerging
Growth Company
i☐
Pepco Holdings LLC
Large Accelerated Filer
☐
Accelerated Filer
☐
iNon-accelerated
Filer
x
Smaller Reporting Company
i☐
Emerging Growth Company
i☐
Potomac
Electric Power Company
Large Accelerated Filer
☐
Accelerated Filer
☐
iNon-accelerated Filer
x
Smaller Reporting Company
i☐
Emerging
Growth Company
i☐
Delmarva Power & Light Company
Large Accelerated Filer
☐
Accelerated Filer
☐
iNon-accelerated
Filer
x
Smaller Reporting Company
i☐
Emerging Growth Company
i☐
Atlantic
City Electric Company
Large Accelerated Filer
☐
Accelerated Filer
☐
iNon-accelerated Filer
x
Smaller Reporting Company
i☐
Emerging
Growth Company
i☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined
in Rule 12b-2 of the Act). Yes i☐ No x
The number of shares outstanding of each registrant’s common stock as of March 31, 2022 was:
Exelon Corporation Common Stock, without par value
i980,209,605
Commonwealth
Edison Company Common Stock, $12.50 par value
i127,021,391
PECO Energy Company Common Stock, without par value
i170,478,507
Baltimore
Gas and Electric Company Common Stock, without par value
i1,000
Pepco Holdings LLC
not applicable
Potomac Electric Power Company Common Stock, $0.01 par value
i100
Delmarva
Power & Light Company Common Stock, $2.25 par value
i1,000
Atlantic City Electric Company Common Stock, $3.00 par value
Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units
Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RFP
Request
for Proposal
Rider
Reconcilable Surcharge Recovery Mechanism
ROE
Return on equity
ROU
Right-of-use
RPS
Renewable Energy Portfolio Standards
RTO
Regional
Transmission Organization
SEC
United States Securities and Exchange Commission
SOFR
Secured Overnight Financing Rate
SOS
Standard Offer Service
STRIDE
Maryland Strategic Infrastructure Development and Enhancement Program
This combined Form 10-Q is being filed separately by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. Words such as “could,”“may,”“expects,”“anticipates,”“will,”“targets,”“goals,”“projects,”“intends,”“plans,”“believes,”“seeks,”“estimates,”“predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements.
The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2021 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 12, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.
Investors are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE
TO FIND MORE INFORMATION
The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended March 31,
(In millions, except per share data)
2022
2021
Operating
revenues
Electric operating revenues
$
i4,481
$
i3,870
Natural
gas operating revenues
i817
i633
Revenues
from alternative revenue programs
i29
i129
Total
operating revenues
i5,327
i4,632
Operating
expenses
Purchased power
i1,581
i1,140
Purchased
fuel
i338
i218
Purchased
power and fuel from affiliates
i159
i293
Operating
and maintenance
i1,178
i1,083
Depreciation
and amortization
i817
i757
Taxes
other than income taxes
i354
i317
Total
operating expenses
i4,427
i3,808
Operating
income
i900
i824
Other
income and (deductions)
Interest expense, net
(i332)
(i312)
Interest
expense to affiliates
(i6)
(i6)
Other,
net
i137
i58
Total
other deductions
(i201)
(i260)
Income
from continuing operations before income taxes
i699
i564
Income
taxes
i218
i39
Net
income from continuing operations after income taxes
i481
i525
Net
income (loss) from discontinued operations after income taxes (Note 2)
i117
(i789)
Net
income (loss)
i598
(i264)
Net
income attributable to noncontrolling interests
i1
i25
Net
income (loss) attributable to common shareholders
$
i597
$
(i289)
Amounts
attributable to common shareholders:
Net income from continuing operations
i481
i525
Net
income (loss) from discontinued operations
i116
(i814)
Net
income (loss) attributable to common shareholders
$
i597
$
(i289)
Comprehensive
income (loss), net of income taxes
Net income (loss)
$
i598
$
(i264)
Other
comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost
i—
(i1)
Actuarial
loss reclassified to periodic benefit cost
i14
i56
Pension
and non-pension postretirement benefit plan valuation adjustment
i—
(i2)
Unrealized
gain on foreign currency translation
i—
i1
Other
comprehensive income
i14
i54
Comprehensive
income (loss)
i612
(i210)
Comprehensive
income attributable to noncontrolling interests
i1
i25
Comprehensive
income (loss) attributable to common shareholders
$
i611
$
(i235)
Average
shares of common stock outstanding:
Basic
i981
i977
Assumed
exercise and/or distributions of stock-based awards
i—
i1
Diluted(a)
i981
i978
Earnings
per average common share from continuing operations
Basic
$
i0.49
$
i0.53
Diluted
$
i0.49
$
i0.53
Earnings
(losses) per average common share from discontinued operations
Basic
$
i0.12
$
(i0.83)
Diluted
$
i0.12
$
(i0.83)
__________
(a)The
number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect were inone and less than i1
million for the three months ended March 31, 2022 and 2021, respectively.
See the Combined Notes to Consolidated Financial Statements
Property,
plant, and equipment (net of accumulated depreciation and amortization of $i14,878 and $i14,430
as of March 31, 2022 and December 31, 2021, respectively)
i65,465
i64,558
Deferred
debits and other assets
Regulatory assets
i8,200
i8,224
Investments
i244
i250
Goodwill
i6,630
i6,630
Receivable
related to Regulatory Agreement Units
i2,969
i—
Other
i1,045
i885
Property,
plant, and equipment, deferred debits, and other assets of discontinued operations
i—
i38,509
Total
deferred debits and other assets
i19,088
i54,498
Total
assets
$
i92,698
$
i133,013
See the Combined Notes to Consolidated Financial Statements
Deferred income taxes and unamortized investment tax credits
i11,089
i10,611
Asset
retirement obligations
i273
i271
Pension
obligations
i1,447
i2,051
Non-pension
postretirement benefit obligations
i800
i811
Regulatory
liabilities
i9,192
i9,628
Mark-to-market
derivative liabilities
i144
i201
Unamortized
energy contract liabilities
i42
i146
Other
i2,187
i1,573
Long-term
debt, deferred credits, and other liabilities of discontinued operations
i—
i25,676
Total
deferred credits and other liabilities
i25,174
i50,968
Total
liabilities
i69,207
i98,218
Commitments
and contingencies
i
i
Shareholders’
equity
Common stock (iiNo/
par value, ii2,000/ shares authorized, i980
shares and i979 shares outstanding at March 31, 2022 and December 31, 2021, respectively)
Property,
plant, and equipment (net of accumulated depreciation and amortization of $i6,267 and $i6,099
as of March 31, 2022 and December 31, 2021, respectively)
i26,325
i25,995
Deferred
debits and other assets
Regulatory assets
i1,883
i1,870
Investments
i6
i6
Goodwill
i2,625
i2,625
Receivables
from affiliates
i—
i2,761
Receivable
related to Regulatory Agreement Units
i2,484
i—
Prepaid
pension asset
i1,245
i1,086
Other
i481
i405
Total
deferred debits and other assets
i8,724
i8,753
Total
assets
$
i37,013
$
i36,470
See
the Combined Notes to Consolidated Financial Statements
Property, plant, and equipment (net of accumulated
depreciation and amortization of $i4,004 and $i3,964
as of March 31, 2022 and December 31, 2021, respectively)
i11,334
i11,117
Deferred
debits and other assets
Regulatory assets
i1,000
i943
Investments
i33
i34
Receivables
from affiliates
i—
i597
Receivable
related to Regulatory Agreement Units
i486
i—
Prepaid
pension asset
i401
i386
Other
i29
i36
Total
deferred debits and other assets
i1,949
i1,996
Total
assets
$
i14,113
$
i13,824
See
the Combined Notes to Consolidated Financial Statements
Property, plant, and equipment (net of accumulated
depreciation and amortization of $i4,376 and $i4,299
as of March 31, 2022 and December 31, 2021, respectively)
i10,736
i10,577
Deferred
debits and other assets
Regulatory assets
i467
i477
Investments
i6
i14
Prepaid
pension asset
i315
i276
Other
i40
i44
Total
deferred debits and other assets
i828
i811
Total
assets
$
i12,509
$
i12,324
See
the Combined Notes to Consolidated Financial Statements
Property,
plant, and equipment (net of accumulated depreciation and amortization of $i2,256 and $i2,108
as of March 31, 2022 and December 31, 2021, respectively)
i16,701
i16,498
Deferred
debits and other assets
Regulatory assets
i1,770
i1,794
Investments
i142
i145
Goodwill
i4,005
i4,005
Prepaid
pension asset
i392
i344
Deferred
income taxes
i5
i8
Other
i253
i258
Total
deferred debits and other assets
i6,567
i6,554
Total
assets
$
i25,636
$
i24,744
See
the Combined Notes to Consolidated Financial Statements
Property,
plant, and equipment (net of accumulated depreciation and amortization of $i3,929 and $i3,875
as of March 31, 2022 and December 31, 2021, respectively)
i8,229
i8,104
Deferred
debits and other assets
Regulatory assets
i496
i532
Investments
i119
i120
Prepaid
pension asset
i279
i279
Other
i58
i59
Total
deferred debits and other assets
i952
i990
Total
assets
$
i10,458
$
i9,903
See
the Combined Notes to Consolidated Financial Statements
Property, plant, and equipment (net of accumulated
depreciation and amortization of $i1,671 and $i1,635
as of March 31, 2022 and December 31, 2021, respectively)
i4,612
i4,560
Deferred
debits and other assets
Regulatory assets
i208
i212
Prepaid
pension asset
i157
i157
Other
i58
i61
Total
deferred debits and other assets
i423
i430
Total
assets
$
i5,573
$
i5,412
See
the Combined Notes to Consolidated Financial Statements
Property, plant, and equipment (net of accumulated
depreciation and amortization of $i1,458 and $i1,420
as of March 31, 2022 and December 31, 2021, respectively)
i3,763
i3,729
Deferred
debits and other assets
Regulatory assets
i559
i430
Prepaid
pension asset
i30
i27
Other
i37
i37
Total
deferred debits and other assets
i626
i494
Total
assets
$
i4,929
$
i4,556
See
the Combined Notes to Consolidated Financial Statements
Exelon is a utility services holding company engaged in the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation. The separation was completed
on February 1, 2022, creating two publicly traded companies, Exelon and Constellation. See Note 2 — Discontinued Operations for additional information.
Name of Registrant
Business
Service Territories
Commonwealth Edison Company
Purchase
and regulated retail sale of electricity
Northern Illinois, including the City of Chicago
Transmission and distribution of electricity to retail customers
PECO Energy Company
Purchase and regulated retail sale of electricity and natural gas
Southeastern Pennsylvania, including the City of Philadelphia (electricity)
Transmission and distribution of electricity and
distribution of natural gas to retail customers
Pennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric Company
Purchase and regulated retail sale of electricity and natural gas
Central Maryland, including the City of Baltimore (electricity and natural gas)
Transmission and distribution of electricity and distribution of natural gas to retail customers
Pepco Holdings LLC
Utility
services holding company engaged, through its reportable segments Pepco, DPL, and ACE
Service Territories of Pepco, DPL, and ACE
Potomac Electric Power Company
Purchase and regulated retail sale of electricity
District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland
Transmission and
distribution of electricity to retail customers
Delmarva Power & Light Company
Purchase and regulated retail sale of electricity and natural gas
Portions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customers
Portions of New Castle County, Delaware (natural gas)
Atlantic City Electric Company
Purchase
and regulated retail sale of electricity
Portions of Southern New Jersey
Transmission and distribution of electricity to retail customers
Basis of Presentation
This is a combined quarterly report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated,
except for the historical transactions between the Utility Registrants and Generation for the purposes of presenting discontinued operations in all periods presented in the Consolidated Statements of Operations and Comprehensive Income.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” in the
consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
The accompanying consolidated financial statements as of March 31, 2022 and for the three months ended March 31, 2022 and 2021 are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 1 — Significant Accounting Policies
December 31, 2021 Consolidated Balance Sheets were derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Additionally, financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2022. These Combined Notes to Consolidated Financial Statements have been prepared pursuant
to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.
The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. 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. Comprehensive income, shareholders' equity, and cash flows related to Constellation have not been segregated and are included in the Consolidated Statements of Operations and Comprehensive
Income, Consolidated Statements of Changes in Shareholders’ Equity, and Consolidated Statements of Cash Flows, respectively, for all periods presented. See Note 2 — Discontinued Operations for additional information.
Prior Period Adjustments and Reclassifications (Exelon, PHI, ACE)
In the first quarter of 2022, management identified an error related to an overstatement of the regulatory liability associated with ACE’s mechanism to recover the cost of Transition Bonds issued in 2002 and 2003 by ACE Funding. Management has concluded that the error was not material to previously issued financial statements for Exelon, PHI or ACE.
The error was corrected through a revision to ACE’s financial statements contained herein. The impact of the error correction was an $i8 million
increase to ACE’s opening Retained earnings as of January 1, 2021 with a corresponding reduction to Regulatory liabilities of $i11 million and an increase to Deferred income taxes and unamortized investment tax credits of $i3 million.
The impact of the error to ACE’s Total operating revenues and Net income was less than $i1 million for the three months ended March 31, 2021. The error did not impact net cash flows provided by operating activities, net cash flows used in investing activities or net cash flows provided by financing activities for the three months ended March 31, 2021.
The error was corrected in the Exelon and PHI financial statements for the three months ended March
31, 2022 as it was not material, resulting in an increase to Net income of $i8 million.
2. iDiscontinued
Operations (Exelon)
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, through the distribution of i326,663,937 common stock shares of Constellation, the new publicly traded company, to Exelon shareholders. Under the separation plan, Exelon shareholders
retained their current shares of Exelon stock and received one share of Constellation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the distribution, in a transaction that is tax-free to Exelon and its shareholders for U.S. federal income tax purposes.
Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purposes of separation and holds Generation (including Generation's subsidiaries).
Pursuant to the separation:
•Exelon entered into four term loans consisting of a 364-day term loan for $i1.15 billion
and three 18-month term loans for $i300 million, $i300 million and $i250 million,
respectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 10 — Debt and Credit Agreements for additional information.
•Exelon made a cash payment of $i1.75 billion to Constellation on January 31, 2022.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Discontinued Operations
•Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation.
•Exelon transferred certain corporate assets and employee-related obligations to Constellation.
•Exelon received cash from Generation of $i258 million
to settle the intercompany loan on January 31, 2022. See Note 10 — Debt and Credit Agreements for additional information.
Continuing Involvement
In order to govern the ongoing relationships between Exelon and Constellation after the separation, and to facilitate an orderly transition, Exelon and Constellation have entered into several agreements, including the following:
•Separation Agreement – governs the rights and obligations between Exelon and Constellation regarding certain actions to be taken in connection with the separation, among others, including the allocation of assets and liabilities between Exelon and Constellation.
•Transition Services Agreement (TSA) – governs the terms and conditions
of the services that Exelon will provide to Constellation and Constellation will provide to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits and other services that have historically been provided on a centralized basis by BSC. For the period from February 1, 2022 to March 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $i56 million
recorded in Other income, net and $i9 million recorded in Operating and maintenance expense, respectively.
•Tax Matters Agreement (TMA) – governs the respective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal,
state, local and foreign income taxes, other tax matters and related tax returns. See Note 7. Income Taxes for additional information.
In addition, the Utility Registrants will continue to incur expenses from transactions with Generation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. After the separation, such expenses are primarily recorded as Purchased power and an immaterial amount recorded as Operating and maintenance expense at the Utility Registrants.
•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.
•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.
•BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.
•Pepco received electric supply from Generation under contracts executed through Pepco’s competitive procurement process approved by the MDPSC and DCPSC.
•DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.
•ACE received electric supply from Generation under contracts executed through
ACE’s competitive procurement process approved by the NJBPU.
ComEd and PECO also have receivables with Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements of the Exelon 2021 Form 10-K and Note 15 — Related Party Transactions for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Discontinued Operations
Discontinued Operations
The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations.
i
The
following table presents the results of Constellation that have been reclassified from continuing operations and included in discontinued operations within Exelon’s Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2022 and March 31, 2021.
These results are primarily Generation, which is comprised of Exelon’s Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions reportable segments, and include the impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to Generation, transactions between Generation and the Utility Registrants, and tax-related adjustments. Transaction costs include costs for external bankers, accountants, appraisers, lawyers, external counsels and other advisors, among
others, who are involved in the negotiation, appraisal, due diligence and regulatory approval of the separation. Transition costs are primarily employee-related costs such as recruitment expenses, costs to establish certain stand-alone functions and information technology systems, professional services fees and other separation-related costs during the transition to separate Generation. For the purposes of reporting discontinued operations, these results also include transactions between Generation and the Utility Registrants that were historically eliminated within Exelon’s Consolidated Statements of Operations as these transactions will be ongoing after the separation. Certain BSC costs that were historically allocated to Generation are presented as part of continuing operations in Exelon’s Consolidated Statements of Operations as these costs do not qualify as expenses of the discontinued operations per the accounting rules.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Discontinued Operations
__________
(a)Includes transaction and transition costs related to the separation of $i52
million and $i3 million for the three months ended March 31, 2022 and 2021, respectively. $i50
million and $i2 million of transaction costs and $i2 million
and less than $i1 million of transition costs are included in the results of discontinued operations in the table presented above for the three months ended March 31, 2022 and March 31, 2021, respectively. See discussion above for additional information.
There were no assets and liabilities of discontinued operations included in Exelon’s
Consolidated Balance Sheet as of March 31, 2022. Constellation had net assets of $i11,573 million that separated on February 1, 2022 that resulted in a reduction to Exelon’s equity during the three months ended March 31, 2022. Refer to the Distribution of Constellation line in Exelon’s Consolidated Statement of Changes in Shareholders’ Equity for further information.
i
The
following table presents the assets and liabilities of discontinued operations in Exelon’s Consolidated Balance Sheet as of December 31, 2021:
Total
current liabilities of discontinued operations
i7,940
Long-term debt
i4,575
Deferred
credits and other liabilities
Deferred income taxes and unamortized investment tax credits
i3,583
Asset retirement obligations
i12,819
Pension
obligations
i939
Non-pension postretirement benefit obligations
i876
Spent
nuclear fuel obligation
i1,210
Mark-to-market derivative liabilities
i513
Other
i1,161
Total
long-term debt, deferred credits, and other liabilities of discontinued operations
i25,676
Total liabilities of discontinued operations
$
i33,616
i
The
following table presents selected financial information regarding cash flows of the discontinued operations that are included within Exelon’s Consolidated Statements of Cash Flows for the three months ended March 31, 2022 and March 31, 2021.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
3. iRegulatory Matters (All Registrants)
As discussed in Note 3 — Regulatory Matters of
the Exelon 2021 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2022 and updates to the 2021 Form 10-K.
Distribution Base Rate Case Proceedings
i
The following tables show the completed and pending distribution base rate case proceedings in 2022.
(a)ComEd's 2022 approved revenue requirement reflects an increase of $i37 million for the initial year revenue requirement for 2022 and an increase of $i9
million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on distribution rate base of i5.72%, inclusive of an allowed ROE of i7.36%,
reflecting the monthly average yields for 30-year treasury bonds plus i580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of i5.69%,
inclusive of an allowed ROE of i7.29%, reflecting the monthly yields on 30-year treasury bonds plus i580 basis points less a performance metrics penalty of i7
basis points.
(b)The PECO electric base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.
(c)Reflects a three-year cumulative multi-year plan for 2021 through 2023. The MDPSC awarded BGE electric revenue requirement increases of $i59 million, $i39
million, and $i42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $i53
million, $i11 million, and $i10 million, before offsets,
in 2021, 2022, and 2023, respectively. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only i25% of the cumulative 2021 and 2022 electric revenue requirement increases and i50%
of the cumulative gas revenue requirement increases. Whether certain tax benefits will be used to offset the customer rate increases in 2023 has not been decided, and BGE cannot predict the outcome.
(d)Reflects a cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $i42 million and $i67 million,
before offsets, for 2021 and 2022, respectively. However, the DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the customer rate increases by $i22 million and $i40 million
for 2021 and 2022, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
(e)Reflects
a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $i21 million, $i16 million,
and $i15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases
such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset i25% of the cumulative revenue requirement increase for the 12-month period ending March 31, 2023. Whether certain tax benefits will be used to offset the customer rate increases for the 12-month period ending March 31, 2024 has not
been decided, and Pepco cannot predict the outcome.
(f)The approved settlement reflects a i9.60% ROE, which is solely for the purposes of calculating AFUDC and regulatory asset carrying costs.
(g)Requested and approved increases are before New Jersey sales and use tax. The order allows ACE to retain approximately $i11 million
of certain tax benefits which resulted in a decrease to income tax expense in Exelon's, PHI's, and ACE's Consolidated Statements of Operations and Comprehensive Income in the third quarter of 2021.
(a)ComEd's 2023 requested revenue requirement reflects an increase of $i144
million for the initial year revenue requirement for 2023 and an increase of $i55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of i5.94%,
inclusive of an allowed ROE of i7.85%, reflecting the average monthly yields for 30-year treasury bonds plus i580 basis points. The reconciliation revenue requirement for
2021 provides for a weighted average debt and equity return on distribution rate base of i5.91%, inclusive of an allowed ROE of i7.78%,
reflecting the average monthly yields for 30-year treasury bonds plus i580 basis points less a performance metrics penalty of i7 basis points. This is ComEd's last performance-based electric distribution
formula rate update filing under EIMA as a result of the law authorizing the rate setting process sunsetting at the end of 2022. See Note 3. - Regulatory Matters of the Exelon 2021 Form 10-K for additional information on ComEd's transition away from the electric distribution formula rate.
(b)The rates will go into effect on August 14, 2022, subject to refund.
Transmission Formula Rates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual
costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for BGE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for BGE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
i
For
2022, the following total increases were included in ComEd’s and BGE's electric transmission formula rate update. PECO, Pepco, DPL, and ACE intend to file by the required deadline for the annual update.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
(a)All rates are effective June 1, 2022 - May 31, 2023, subject to review by interested parties pursuant to review protocols of ComEd's and BGE's tariff.
(b)The increase in BGE's transmission revenue requirement includes a $i5
million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.
(c)Represents the weighted average debt and equity return on transmission rate bases.
(d)As part of the FERC-approved settlements of ComEd’s 2007 transmission rate case, the rate of return on common equity is i11.50%, inclusive of a i50-basis-point
incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at i55%. As part of the FERC-approved settlement of the ROE complaint against BGE, the rate of return on common equity is i10.50%,
inclusive of a i50-basis-point incentive adder for being a member of a RTO.
Other State Regulatory Matters
Illinois Regulatory Matters
CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate
case or a new four-year multi-year plan no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes ("EDIT") that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics.Regulatory or legal challenges regarding the validity or
implementation of CEJA are possible and Exelon and ComEd cannot reasonably predict the outcome of any such challenges.
The ICC initiated a docket to accelerate and fully credit to customers TCJA unprotected property-related EDIT no later than December 31, 2025. On April 13, 2022, a stipulation and agreement on the schedule for the acceleration of EDIT amortization was submitted by ComEd, the Illinois Attorney General's Office, and the Citizens Utility Board. At this time, ComEd cannot predict an outcome of these proceedings.
See Note 3 — Regulatory Matters of the Exelon 2021 Form 10-K for additional information on CEJA (referred to as Clean Energy Law).
New Jersey Regulatory Matters
Termination
of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE).
On December 22, 2021, ACE filed with the NJBPU a petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $i203
million for the contract termination fee, which is to be paid by the end of 2024, and recognized a corresponding regulatory asset of $i203 million.
As of March 31, 2022, the $i203
million liability for the contract termination fee consists of $i85 million and $i118 million included in Other current liabilities and Other deferred credits and other liabilities, respectively,
in Exelon's Consolidated Balance Sheet. As of March 31, 2022, the current and noncurrent liability is included in PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets.
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2021, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2021 Form 10-K for additional information on the specific regulatory assets and liabilities.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Regulatory Matters
PECO. Regulatory assets increased $i66 million primarily due to an increase
of $i60 million in the Deferred Income Taxes regulatory asset. Regulatory liabilities decreased by $i112 million
primarily due to a decrease of $i111 million in the Nuclear Decommissioning regulatory liability.
BGE. Regulatory assets decreased $i50 million
primarily due to a decrease of $i19 million in the Electric Energy and Natural Gas Costs regulatory asset and $i16 million
in the Energy Efficiency and Demand Response Programs regulatory asset. Regulatory liabilities decreased $i53 million primarily due to a decrease of $i65 million
in the Deferred Income Taxes regulatory liability.
ACE. Regulatory assets increased $i205 million primarily due to an increase in the Electric Energy Costs regulatory asset as a result of the PPA termination. Regulatory liabilities decreased $i19 million
primarily due to a decrease of $i9 million in the Deferred Income Taxes regulatory liability and $i5 million
in the Electric Energy Costs regulatory liability.
Capitalized Ratemaking Amounts Not Recognized
i
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers.
(a)Reflects
ComEd's unrecognized equity returns earned for ratemaking purposes on its energy efficiency and electric distribution formula rate regulatory assets.
(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholder's investment on its AMI programs.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholder's investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs, and for Pepco District of Columbia revenue decoupling program. The earnings on energy efficiency are on Pepco District of Columbia and DPL Delaware programs only.
/
4. iRevenue
from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services.
See Note 4 — Revenue from Contracts with Customers of the Exelon 2021 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
Contract Liabilities
The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other
noncurrent liabilities in their Consolidated Balance Sheets.
For PHI, Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement with an unrelated owner and manager of communication infrastructure. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.
Revenues recognized were immaterial for Exelon, PHI, Pepco, DPL, and ACE for the three months ended March 31, 2022 and 2021. As of March 31, 2022 and December 31, 2021, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
Transaction Price Allocated to Remaining Performance Obligations
i
The
following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of March 31, 2022. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.
2022
2023
2024
2025
2026
and thereafter
Total
Exelon
$
i6
$
i8
$
i6
$
i5
$
i82
$
i107
PHI
i6
i8
i6
i5
i82
i107
Pepco
i4
i6
i5
i5
i65
i85
DPL
i1
i1
i—
i—
i9
i11
ACE
i1
i1
i1
i—
i8
i11
/
Revenue
Disaggregation
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.
5. iSegment Information (All Registrants)
Operating
segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has isix reportable segments, which include ComEd, PECO, BGE, and PHI's ithree
reportable segments consisting of Pepco, DPL, and ACE. 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.
iAn analysis and reconciliation of the Registrants’ reportable segment information to the respective information
in the consolidated financial statements for the three months ended March 31, 2022 and 2021 is as follows:
(a)Other
primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.
(a)Other
primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.
(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Segment Information
i
The following tables disaggregate the Registrants' revenues recognized
from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.
(a)For
PECO, BGE and ACE, the increase is primarily as a result of increased receivable balances due to the increased aging of receivables. For BGE, also reflects increased receivable balance due to colder weather.
(b)Recoveries were not material to the Registrants.
(c)For ACE, the increase in 2022 is primarily related to the termination of the moratorium, which beginning in March 2020, prevented customer disconnections for non-payment. With disconnection activities restarting in January 2022, write-offs of aging accounts receivable increased throughout the year.
(d)The increase is primarily as a result of increased receivable balances due to the colder weather and the increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary
cessation of new late payment fees, and reconnection of service for customers previously disconnected due to COVID-19.
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Accounts Receivable
__________
(a)Recoveries were not material to the Registrants.
Unbilled Customer Revenue
i
The
following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of March 31, 2022 and December 31, 2021.
(a)Unbilled
customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.
/
Other Purchases of Customer and Other Accounts Receivables
i
The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District
of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following tables present the total receivables purchased.
State income taxes, net of Federal income tax benefit
i2.8
i6.8
(i1.6)
(i10.1)
i6.1
i5.5
i6.4
i6.9
Plant
basis differences
(i3.4)
(i0.6)
(i10.5)
(i1.4)
(i1.5)
(i2.1)
(i0.7)
(i0.9)
Excess
deferred tax amortization
(i12.0)
(i6.9)
(i3.2)
(i15.5)
(i19.3)
(i15.1)
(i18.5)
(i28.7)
Amortization
of investment tax credit, including deferred taxes on basis difference
(i0.1)
(i0.1)
i—
(i0.1)
(i0.1)
i—
(i0.2)
(i0.2)
Tax
credits
(i0.3)
(i0.2)
i—
(i0.4)
(i0.2)
(i0.2)
(i0.1)
(i0.3)
Other
(i1.1)
(i3.5)
(i0.1)
(i0.1)
(i0.1)
i0.1
i0.3
i2.2
Effective
income tax rate
i6.9
%
i16.5
%
i5.6
%
(i6.6)
%
i5.9
%
i9.2
%
i8.2
%
i—
%
__________
(a)Positive
percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions. For BGE, the lower effective tax rate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For Pepco, the income tax benefit is primarily due to the Maryland and Washington, D.C. multi-year plans which resulted in the acceleration of certain income tax benefits. For ACE, the lower effective tax rate is primarily due to the acceleration of certain income tax benefits due to distribution rate case settlements.
(c)For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate
change of approximately $i67 million and the recognition of a valuation allowance of approximately $i40
million against the net deferred tax asset position for certain standalone state filing jurisdictions as a result of the separation.
(d)For Exelon, reflects the income tax expense related to the write-off of federal tax credits subject to recapture of approximately $i15 million as a result of the separation.
(e)For Exelon, primarily reflects the nondeductible transaction costs of approximately $i19
million arising as part of the separation.
(f)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions. For BGE, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of
COMBINED NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Income Taxes
certain income tax benefits. For ACE, the lower effective tax rate is primarily due to the acceleration of certain income tax benefits due to distribution rate case settlements.
Unrecognized Tax Benefits
i
Exelon,
PHI and ACE have the following unrecognized tax benefits as of March 31, 2022 and December 31, 2021. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
(a)As
of March 31, 2022, Exelon recorded a receivable of approximately $i50 million in Noncurrent other assets in the Consolidated Balance Sheet for Constellation’s share of unrecognized tax benefits for periods prior to the separation.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
As of March 31,
2022, ACE has approximately $i14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Other Tax Matters
Separation
(Exelon)
In connection with the separation, Exelon recorded an income tax expense related to continuing operations of approximately $i148 million primarily due to the long-term marginal state income tax rate change of approximately $i67
million discussed further below, the recognition of valuation allowances of approximately $i40 million against the net deferred tax assets positions for certain standalone state filing jurisdictions, the write-off of federal and state tax credits subject to recapture of approximately $i17
million, and nondeductible transaction costs for federal and state taxes of approximately $i24 million.
Tax Matters Agreement (Exelon)
In connection with the separation, Exelon entered into a TMA with Constellation. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years
that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes.
Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the existing Exelon tax sharing agreement. As of March 31, 2022, Exelon recorded a receivable of approximately $i55
million in Current other assets in the Consolidated Balance Sheet for Constellation’s share of taxes for periods prior to the separation.
Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement.
Tax Attributes. At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA also provides that Exelon will reimburse Constellation when those allocated tax credit carryforwards are utilized. As of March 31, 2022,
Exelon recorded a payable of approximately $i11 million and $i484 million in Current other liabilities and Noncurrent other liabilities, respectively, in the Consolidated Balance Sheet for tax credit carryforwards
that are expected to be utilized and reimbursed to Constellation.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Income Taxes
Long-Term Marginal State Income Tax Rate (All Registrants)
In the first
quarter of 2022, Exelon updated its marginal state income tax rates for changes in state apportionment due to the separation, which resulted in an increase of approximately $i67 million to the deferred tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes.
8. iRetirement
Benefits (All Registrants)
Defined Benefit Pension and OPEB
Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and assets for current and former employees of the Constellation business and certain other former employees of Exelon and its subsidiaries transferred to pension and OPEB plans and trusts maintained by Constellation or its subsidiaries. The Exelon New England Union Employees Pension Plan and Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B were transferred. The following OPEB plans were also transferred: Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan, Exelon New England Union Post-Employment Medical Savings Account Plan, and the Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for
Retired Employees.
As a result of the separation, Exelon restructured certain of its qualified pension plans. Pension obligations and assets for current and former employees continuing with Exelon and who are participants in the Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek, Pension Plan of Constellation Energy Nuclear Group, LLC, and Nine Mile Point Pension Plan were merged into the Pension Plan of Constellation Energy Group, Inc, which was subsequently renamed, Exelon Pension Plan (EPP). Exelon employees who participated in these plans prior to the separation now participate in the EPP. The merging of the plans did not change the benefits offered to the plan participants and, thus, had no impact on Exelon's pension obligations.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 8 — Retirement Benefits
Operating
Company(a)
Name of Plan:
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
OPEB Plans:
PECO
Energy Company Retiree Medical Plan
X
X
X
X
X
X
X
Exelon Corporation Health Care Program
X
X
X
X
X
X
X
Exelon
Corporation Employees’ Life Insurance Plan
X
X
X
Exelon Corporation Health Reimbursement Arrangement Plan
X
X
X
BGE
Retiree Medical Plan
X
X
X
X
X
X
BGE Retiree Dental Plan
X
Exelon
Employee Life Insurance Plan and Family Life Insurance Plan
X
X
X
X
X
Exelon Retiree Medical Plan of Constellation Energy Nuclear Group, LLC
X
X
X
Exelon
Retiree Dental Plan of Constellation Energy Nuclear Group, LLC
X
X
X
Pepco Holdings LLC Welfare Plan for Retirees
X
X
X
X
X
X
X
__________
(a)Employees
generally remain in their legacy benefit plans when transferring between operating companies.
As of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. The remeasurement and separation resulted in a decrease to the pension obligation, net of plan assets, of $i921 million and a decrease to the OPEB obligation of $i893
million. Additionally, accumulated other comprehensive loss, decreased by $i1,994 million (after-tax) and regulatory assets and liabilities increased by $i14
million and $i5 million respectively. Key assumptions were held consistent with the year end December 31, 2021 assumptions with the exception of the discount rate.
The majority of the 2022 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of i7.00%
and a discount rate of i3.24%. The majority of the 2022 OPEB cost is calculated using an expected long-term rate of return on plan assets of i6.44%
for funded plans and a discount rate of i3.20%.
During the first quarter of 2022, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of February 1, 2022. This valuation resulted in a decrease to the pension obligation of $i24
million and an increase to the OPEB obligation of $i5 million. Additionally, accumulated other comprehensive loss increased by $i5
million (after-tax) and regulatory assets and liabilities decreased by $i30 million and $i3
million, respectively.
iA portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three months ended March 31, 2022 and 2021.
The
amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
Three
Months Ended March 31,
Pension and OPEB Costs
2022
2021
Exelon
$
i42
$
i69
ComEd
i16
i32
PECO
(i2)
i2
BGE
i11
i15
PHI
i13
i12
Pepco
i2
i2
DPL
i1
i1
ACE
i3
i3
/
Defined
Contribution Savings Plan
i
The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is 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 for the three months ended March 31, 2022
and 2021, respectively.
The
Registrants use derivative instruments to manage commodity price risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying
physical commodity is sold or consumed.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
Commodity Price Risk
The Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs
are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Derivative Financial Instruments
regulatory-approved
recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
Registrant
Commodity
Accounting Treatment
Hedging Instrument
ComEd
Electricity
NPNS
Fixed
price contracts based on all requirements in the IPA procurement plans.
Electricity
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)
20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately i1.3
million MWhs per year.
PECO
Electricity
NPNS
Fixed price contracts for default supply requirements through full requirements contracts.
Gas
NPNS
Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGE
Electricity
NPNS
Fixed price contracts for all SOS requirements
through full requirements contracts.
Gas
NPNS
Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco
Electricity
NPNS
Fixed price contracts for all SOS requirements through full requirements contracts.
DPL
Electricity
NPNS
Fixed price
contracts for all SOS requirements through full requirements contracts.
Gas
NPNS
Fixed and index priced contracts through full requirements contracts.
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)
Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE
Electricity
NPNS
Fixed
price contracts for all BGS requirements through full requirements contracts.
__________
(a)See Note 3 — Regulatory Matters of the 2021 Form 10-K for additional information.
The fair value of derivative economic hedges is presented in current and noncurrent Mark-to-market derivative liabilities in Exelon's and ComEd's Consolidated Balance Sheets.
Credit Risk
The Registrants would be exposed to credit-related losses in the event of non-performance by
counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of March 31, 2022, the amount of cash collateral held with external counterparties by Exelon, ComEd, PHI, and DPL was $i192
million, $i72 million, $i86 million, and $i73
million, respectively, which is recorded in Other current liabilities in Exelon's, ComEd's, PHI's, and DPL's Consolidated Balance Sheets. The amounts for PECO, BGE, Pepco, and ACE were not material as of March 31, 2022. As of December 31, 2021, the amounts for ComEd and DPL were $i41 million and $i43
million, respectively. The amounts for Exelon, PECO, BGE, PHI, Pepco, and ACE were not material as of December 31, 2021.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Derivative Financial Instruments
The
Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of March 31, 2022, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of March 31, 2022, they could have been required to post collateral to their counterparties of $i39
million, $i62 million, and $i16 million, respectively.
10. iDebt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets their 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 borrowings from 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.
(b)Represents the consolidated amounts of Pepco, DPL, and ACE.
/
Revolving Credit Agreements
i
On February 1, 2022, Exelon Corporate and the Utility Registrants' each entered into a new 5-year revolving credit
facility that replaced its existing syndicated revolving credit facility. The following table reflects the credit agreements:
Borrower
Aggregate Bank Commitment
Interest Rate
Exelon Corporate
i900
SOFR plus i1.275
%
ComEd
i1,000
SOFR plus i1.000
%
PECO
i600
SOFR plus i0.900
%
BGE
i600
SOFR plus i0.900
%
Pepco
i300
SOFR plus i1.075
%
DPL
i300
SOFR plus i1.000
%
ACE
i300
SOFR plus i1.075
%
/
See
Note 17 — Debt and Credit Agreements of the Exelon 2021 Form 10-K for additional information on the Registrants' credit facilities.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Debt and Credit Agreements
Short-Term Loan Agreements
On
March 23, 2017, Exelon Corporate entered into a term loan agreement for $i500 million. The loan agreement was renewed on March 14, 2022 and will expire on March 16, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to iSOFR
plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
On March 31, 2021, Exelon Corporate entered into a 364-day term loan agreement for $i150 million with a variable interest rate of iLIBOR
plus 0.65% and an expiration date of March 30, 2022. Exelon Corporate repaid the term loan on March 30, 2022.
In connection with the separation, on January 24, 2022, Exelon Corporate entered into a 364-day term loan agreement for $i1.15 billion. The loan agreement will expire on January 23, 2023. Pursuant to the
loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus i0.75% with a i22.5 basis point increase commencing on July 24, 2022. All indebtedness pursuant to the loan agreement is unsecured.
Repay
existing indebtedness and for general corporate purposes.
ACE
First Mortgage Bonds
i3.06%
February 15, 2052
i150
Repay
existing indebtedness and for general corporate purposes.
__________
(a)On
March 24, 2022, Pepco entered into a purchase agreement of First Mortgage Bonds of $i225 million at i3.35% due on September
15, 2032. The closing date of the issuance is expected to occur in September 2022.
/
Long-Term Debt to Affiliates
As of December 31, 2021, Exelon Corporate had $i319 million recorded to intercompany notes receivable from Generation. See Note 17 — Debt and Credit Agreements of the Exelon 2021 Form
10-K for additional information. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $i258 million to settle the intercompany loan.
Debt Covenants
As of March 31, 2022, the Registrants are in compliance with debt covenants.
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
11. iFair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures
and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
•Level 2 - inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•Level 3 - unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
i
Fair
Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of March 31, 2022 and December 31, 2021. The Registrants have iiiiiiiiiiiiiiiiiiiiiino/////////////////////
financial liabilities classified as Level 1.
The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
Long-Term Debt, including amounts due within one year(a)
Exelon
$
i37,162
$
i35,174
$
i2,645
$
i37,819
$
i32,902
$
i34,897
$
i2,217
$
i37,114
ComEd
i10,515
i10,894
i—
i10,894
i9,773
i11,305
i—
i11,305
PECO
i4,198
i4,244
i50
i4,294
i4,197
i4,740
i50
i4,790
BGE
i3,961
i3,969
i—
i3,969
i3,961
i4,406
i—
i4,406
PHI
i8,233
i5,453
i2,595
i8,048
i7,547
i5,970
i2,167
i8,137
Pepco
i3,841
i2,901
i1,272
i4,173
i3,445
i3,201
i975
i4,176
DPL
i1,935
i1,300
i592
i1,892
i1,810
i1,426
i552
i1,978
ACE
i1,757
i1,007
i732
i1,739
i1,582
i1,091
i641
i1,732
Long-Term
Debt to Financing Trusts
Exelon
$
i390
$
i—
$
i435
$
i435
$
i390
$
i—
$
i470
$
i470
ComEd
i205
i—
i228
i228
i205
i—
i248
i248
PECO
i184
i—
i207
i207
i184
i—
i222
i222
__________
/
(a)Includes
unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 17 - Debt and Credit Agreements of the Exelon 2021 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 11 - Leases of the Exelon 2021 Form 10-K for finance lease liabilities.
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
i
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants'
Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2022 and December 31, 2021:
(a)Exelon
excludes cash of $i470 million and $i464 million as of March 31, 2022
and December 31, 2021, respectively, and restricted cash of $i110 million and $i49
million as of March 31, 2022 and December 31, 2021, respectively, and includes long-term restricted cash of $i92 million and $i44
million as of March 31, 2022 and December 31, 2021, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
(a)ComEd
excludes cash of $i71 million and $i105 million as of March 31, 2022
and December 31, 2021, respectively, and restricted cash of $i73 million and $i42
million as of March 31, 2022 and December 31, 2021, respectively, and includes long-term restricted cash of $ii92/
million and $i43 million as of March 31, 2022 and December 31, 2021, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $i25
million and $i35 million as of March 31, 2022 and December 31, 2021, respectively. BGE excludes cash of $i41
million and $i51 million as of March 31, 2022 and December 31, 2021, respectively, and restricted cash of $i34
million and $i4 million as of March 31, 2022 and December 31, 2021, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of inone
and $i144 million, respectively, as of March 31, 2022 and $i18 million and $i201
million, respectively, as of December 31, 2021 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
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
i
Reconciliation
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 recurring basis during the three months ended March 31, 2022 and 2021:
The
amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities as of March 31, 2021
$
i1
$
i—
$
ii1/
__________
(a)Classified
in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
/
(b)Includes $i69
million of increases in fair value and an increase for realized losses due to settlements of $i6 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. Includes $i2
million of decreases in fair value and an increase for realized losses due to settlements of $i8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2021.
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 tables below are in accordance with the policies discussed in Note 18 — Fair Value of Financial Assets and Liabilities of the Exelon 2021 Form 10-K.
(a)Quoted
forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates.
/
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair value of the above instruments if they were adjusted. An increase to the marketability reserves would decrease the fair value. An increase to the forward heat rate or renewable factor would increase the fair value accordingly.
12. iCommitments
and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 19 — Commitments and Contingencies of the Exelon 2021 Form 10-K.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. iThe
following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of March 31, 2022:
Description
Exelon
PHI
Pepco
DPL
ACE
Total commitments
$
i513
$
i320
$
i120
$
i89
$
i111
Remaining
commitments(a)
i65
i55
i46
i6
i3
__________
(a)Remaining
commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.
In addition, Exelon has committed to purchase i100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of i120
MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first i40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second i40 MW wind REC tranche was conducted in 2018 and
resulted in a proposed REC purchase agreement that was approved by the DEPSC in 2019. The RFP for the third and final i40 MW wind REC tranche will be conducted in the second half of 2022.
COMBINED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
Commercial Commitments (All Registrants).iThe Registrants’ commercial commitments as of March 31, 2022, representing commitments potentially triggered
by future events were as follows:
Expiration
within
Total
2022
2023
2024
2025
2026
2027 and beyond
Exelon
Letters
of credit
$
i14
$
i12
$
i2
$
i—
$
i—
$
i—
$
i—
Surety
bonds(a)
i201
i188
i11
i2
i—
i—
i—
Financing
trust guarantees
i378
i—
i—
i—
i—
i—
i378
Guaranteed
lease residual values(b)
i30
i1
i3
i6
i5
i5
i10
Total
commercial commitments
$
i623
$
i201
$
i16
$
i8
$
i5
$
i5
$
i388
ComEd
Letters
of credit
$
i7
$
i7
$
i—
$
i—
$
i—
$
i—
$
i—
Surety
bonds(a)
i17
i12
i3
i2
i—
i—
i—
Financing
trust guarantees
i200
i—
i—
i—
i—
i—
i200
Total
commercial commitments
$
i224
$
i19
$
i3
$
i2
$
i—
$
i—
$
i200
PECO
Letters
of credit
$
i1
$
i1
$
i—
$
i—
$
i—
$
i—
$
i—
Surety
bonds(a)
i3
i2
i1
i—
i—
i—
i—
Financing
trust guarantees
i178
i—
i—
i—
i—
i—
i178
Total
commercial commitments
$
i182
$
i3
$
i1
$
i—
$
i—
$
i—
$
i178
BGE
Letters
of credit
$
i2
$
i2
$
i—
$
i—
$
i—
$
i—
$
i—
Surety
bonds(a)
i4
i3
i1
i—
i—
i—
i—
Total
commercial commitments
$
i6
$
i5
$
i1
$
i—
$
i—
$
i—
$
i—
PHI
Surety
bonds(a)
$
i94
$
i91
$
i3
$
i—
$
i—
$
i—
$
i—
Guaranteed
lease residual values(b)
i30
i1
i3
i6
i5
i5
i10
Total
commercial commitments
$
i124
$
i92
$
i6
$
i6
$
i5
$
i5
$
i10
Pepco
Surety
bonds(a)
$
i84
$
i84
$
i—
$
i—
$
i—
$
i—
$
i—
Guaranteed
lease residual values(b)
i10
i—
i1
i2
i2
i2
i3
Total
commercial commitments
$
i94
$
i84
$
i1
$
i2
$
i2
$
i2
$
i3
DPL
Surety
bonds(a)
$
i6
$
i3
$
i3
$
i—
$
i—
$
i—
$
i—
Guaranteed
lease residual values(b)
i13
i1
i1
i3
i2
i2
i4
Total
commercial commitments
$
i19
$
i4
$
i4
$
i3
$
i2
$
i2
$
i4
ACE
Surety
bonds(a)
$
i4
$
i4
$
i—
$
i—
$
i—
$
i—
$
i—
Guaranteed
lease residual values(b)
i7
i—
i1
i1
i1
i1
i3
Total
commercial commitments
$
i11
$
i4
$
i1
$
i1
$
i1
$
i1
$
i3
__________
(a)Surety
bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
(b)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 lease term associated with these assets ranges from i1 to i8 years. The maximum potential obligation at the end of the minimum lease term would be $ii73/
million guaranteed by Exelon and PHI, of which $i25 million, $i30 million, and $i18
million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal 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 these sites, there
are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has i21 sites 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 2031.
•PECO has i6
sites that 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 2023.
•BGE has i4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2023.
•DPL has i1
site that is currently under study and the required cost at the site is not expected to be material.
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 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.
ComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are
currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note
12 — Commitments and Contingencies
i
As of March 31, 2022 and December 31, 2021, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:
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
$
i354
$
i305
$
i352
$
i303
ComEd
i279
i279
i279
i279
PECO
i21
i20
i22
i20
BGE
i7
i6
i6
i4
PHI
i42
i—
i42
i—
Pepco
i40
i—
i40
i—
DPL
i1
i—
i1
i—
ACE
i1
i—
i1
i—
/
Benning
Road 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 an electric generating facility owned by Pepco subsidiary, Pepco Energy Services, which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 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 Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility
Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.
Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which DOEE approved on February 3, 2020. The Pepco Entities are developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2022. After
completion and approval of the FS, DOEE will prepare a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying any further response actions determined to be necessary. 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, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon,
PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS, being performed by the Pepco Entities, DOEE and National Park Service ("NPS") have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by the Pepco Entities 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. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing.
Exelon, PHI, and Pepco have determined that
it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs. On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note
12 — Commitments and Contingencies
approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate 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 plan for the Benning Road site to proceed to conclusion. Pepco concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
On July 12, 2021, DOEE and NPS held a virtual meeting with the PRP's in response to a General Notice
Letter sent by each agency inviting the PRP's to participate in discussions, which Pepco attended.
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 became aware that the Trustees are in the beginning stages of a Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. 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.
Litigation
and Regulatory Matters
Deferred Prosecution Agreement (DPA) and Related Matters (Exelon and ComEd). Exelon and ComEd received 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 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 and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA 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 those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the U.S. Treasury of $i200
million, which was paid in November 2020. Exelon was not made party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the 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 DPA and the SEC's investigation, including:
•Four
putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, the Citizens Utility Board (CUB) filed a motion to intervene in these cases
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note
12 — Commitments and Contingencies
on October 22, 2020 which was granted on December 23, 2020. On December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. However, the Potter plaintiffs voluntarily dismissed their complaint without prejudice on April 5, 2021. ComEd and Exelon
moved to dismiss the consolidated class action complaint and CUB’s complaint on February 4, 2021 and briefing was completed on March 22, 2021. On March 25, 2021, the parties agreed, along with state court plaintiffs, discussed below, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On September 9, 2021, the federal 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. Plaintiffs' opening appeal brief in the Seventh Circuit was filed on January 14, 2022. Exelon and ComEd filed their response brief on March 7, 2022, and plaintiffs filed their reply brief on April 6, 2022. The court has scheduled oral argument for May 17, 2022.
•Three putative class action lawsuits against ComEd and Exelon 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 Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding 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 mediation. 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 dismiss 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 Appeals. On February 15, 2022, Exelon and 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. Plaintiffs' opening appellate briefs are currently due June 3, 2022.
•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 related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and 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 9, 2021, the U.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. On February 10, 2022, the court granted an extension of the amendment to the protective order, at the U.S. government's request, to May 15, 2022 and directed the parties to submit a proposed joint schedule for the additional case proceedings by May 13, 2022.
COMBINED NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments and Contingencies
•Several shareholders have sent letters to the Exelon Board of Directors from 2020 through May 2022 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 conduct 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 investigate and address these shareholders’ allegations and make recommendations to the Exelon
Board of Directors based on the outcome 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. On January 31, 2022, the parties jointly moved the court to extend the stay an additional 120 days.
•Two separate shareholder requests seeking review of certain Exelon books and records were received in August 2021 and January 2022. Exelon responded to both requests and both shareholders have since sent
formal shareholder demands to the Exelon Board, as discussed 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.
The ICC continues to conduct an investigation into rate impacts of conduct admitted in the DPA initiated on August 12, 2021. On December 16, 2021, ComEd filed direct testimony addressing the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. In that testimony, ComEd proposed to voluntarily refund to customers compensation costs of the former officers charged with wrongdoing in connection with events described in the DPA for the period during
which those events occurred as well as costs, previously proposed to be returned, of individuals and entities specifically identified in the DPA, as well as individuals and entities who were referred to ComEd as part of the conduct described in the DPA and who failed, during their tenure at ComEd, to perform work to management expectations. The testimony supports the calculation of the refund amount and proposes a refund mechanism (one-time bill credit in April 2023) and also addresses other topics outlined by statute and the ICC orders initiating the investigation. On April 14, 2022, in response to rebuttal testimony from ICC staff and the Illinois Attorney General, City of Chicago, and CUB, ComEd filed surrebuttal testimony, in which ComEd proposed to increase its voluntary customer refund to $i38
million of ICC and FERC jurisdictional amounts, and estimated interest to resolve the issue of the potential expenditure of customer monies on activities identified in the DPA in this matter. An accrual for the amount of the voluntary customer refund has been recorded in Other deferred credits and other liabilities in Exelon’s and ComEd’s Consolidated Balance Sheets as of March 31, 2022. The voluntary 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. The evidentiary hearing on the remaining contested issue was held on April 28, 2022. A final order is expected by September 9, 2022.
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 the 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. The plaintiffs filed their response brief on March 28, 2022 and the defendants filed their reply on April 11, 2022. On March 4, 2022, the Chamber of Commerce filed a brief of amicus curiae in support of the defendants' motion to dismiss. No loss contingencies have been reflected in Exelon’s consolidated financial statements with respect to this matter, as such contingencies are neither probable nor reasonably estimable at this time.
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 assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Commitments
and Contingencies
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.
13. iChanges
in Accumulated Other Comprehensive Income (Exelon)
i
The following tables present changes in Exelon's AOCI, net of tax, by component:
(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 8 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
i
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
Pension and non-pension postretirement benefit plans:
Prior
service benefit reclassified to periodic benefit cost
$
i—
$
i1
Actuarial
loss reclassified to periodic benefit cost
(i5)
(i19)
/
14. iSupplemental
Financial Information (All Registrants)
Supplemental Statement of Operations Information
iThe following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income:
(a)The
Registrants' utility taxes represent 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 in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Amortization
of energy contract assets and liabilities(c)
i4
i—
i—
i—
i—
i—
i—
i—
Nuclear
fuel(d)
i276
i—
i—
i—
i—
i—
i—
i—
ARO
accretion(e)
i127
i—
i—
i—
i—
i—
i—
i—
Total
depreciation, amortization, and accretion
$
i2,104
$
i292
$
i86
$
i152
$
i210
$
i102
$
i53
$
i47
__________
(a)Exelon's
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 Operating revenues or Purchased power and fuel expense in the Registrants’ 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.
Pension and non-pension postretirement benefit costs
$
i95
$
i32
$
i2
$
i14
$
i12
$
i2
$
i1
$
i3
Allowance
for credit losses
i85
i13
i24
i4
i10
i5
i4
i1
Other
decommissioning-related activity
(i322)
i—
i—
i—
i—
i—
i—
i—
Energy-related
options
i17
i—
i—
i—
i—
i—
i—
i—
True-up
adjustments to decoupling mechanisms and formula rates(b)
(i129)
(i54)
(i10)
(i18)
(i46)
(i26)
(i9)
(i11)
Long-term
incentive plan
i32
i—
i—
i—
i—
i—
i—
i—
Amortization
of operating ROU asset
i37
i—
i—
i7
i7
i1
i3
i1
AFUDC
— Equity
(i28)
(i4)
(i6)
(i7)
(i11)
(i9)
(i1)
(i1)
__________
(a)Exelon's
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 BGE, Pepco, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rates. See Note 3 — Regulatory Matters of the Exelon Form 10-K for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — 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.
(a)Primarily
includes accrued payroll, bonuses and other incentives, vacation, and benefits.
/
15. iRelated Party Transactions (All Registrants)
Utility Registrants' expense with Generation
i
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 affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:
(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 15 — 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.
i
The
following table presents the service company costs allocated to the Registrants:
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. ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
Noncurrent Receivables from affiliates
ComEd and PECO have noncurrent receivables with Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. The receivables are recorded in Receivable related to Regulatory Agreement Units as of March
31, 2022 and in noncurrent Receivables from affiliates as of December 31, 2021. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements of the Exelon 2021 Form 10-K for additional information.
Long-term debt to financing trusts
iThe following table presents Long-term debt to financing trusts:
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 is a utility services holding company engaged in the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Exelon has six reportable segments consisting of ComEd, PECO, BGE, Pepco, DPL,
and ACE. See Note 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.
Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, 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, 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. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders from continuing operations and the Utility Registrants' Net income for the three months ended March 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the three months ended March 31, 2022 and 2021 see the discussions of Results of Operations by Registrant.
Three
Months Ended March 31,
(Unfavorable) Favorable Variance
2022
2021
Exelon
$
481
$
i525
$
(44)
ComEd
188
197
(9)
PECO
206
167
39
BGE
198
209
(11)
PHI
130
128
2
Pepco
46
59
(13)
DPL
56
56
—
ACE
26
14
12
Other(a)
(241)
(176)
(65)
__________
(a)Primarily
includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing 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 all periods presented.
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. See further discussion below.
Three Months Ended March
31, 2022 Compared to Three Months Ended March 31, 2021. Net income attributable to common shareholders from continuing operations decreased by $44 million and diluted
earnings per average common share from continuing operations decreased to $0.49 in 2022 from $0.53 in 2021 primarily due to:
•An income tax expense recorded in connection with
the separation 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;
•Higher depreciation expense at BGE and PHI; and
•Higher storm costs at PHI.
The decreases were partially offset by:
•Higher electric distribution earnings from higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates at ComEd;
•The favorable impacts of regulatory rate increases at PECO, BGE, and PHI; and
•Lower
BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but do not qualify as expenses of the discontinued operation per the accounting rules. Such costs, on a pre-tax basis, were $28 million for the period in 2022 prior to the separation on February 1, 2022 (January 1, 2022 to January 31, 2022) and $106 million for the three months ended March 31, 2021.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (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 year-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 table provides a reconciliation between net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three months ended March 31, 2022 compared to the same period in 2021.
Net Income Attributable to Common Shareholders from Continuing Operations
$
481
$
0.49
$
i525
$
0.53
Mark-to-Market
Impact of Economic Hedging Activities (net of taxes of $1)
—
—
(1)
—
COVID-19 Direct Costs (net of taxes of $1)(a)
—
—
2
—
Acquisition
Related Costs (net of taxes of $2)(b)
—
—
6
0.01
ERP System Implementation Costs (net of taxes of $0 and $2, respectively)(c)
1
—
5
0.01
Separation
Costs (net of taxes of $7 and $1, respectively)(d)
17
0.02
5
0.01
Income Tax-Related Adjustments (entire amount represents tax expense)(e)
134
0.14
—
—
Adjusted
(non-GAAP) Operating Earnings
$
634
$
0.64
$
542
$
0.55
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income from Continuing Operations 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. The marginal statutory income tax rates for 2022 and 2021 ranged from 24.0% to 29.0%.
(a)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees, which are recorded in Operating and maintenance expense.
(b)Reflects certain BSC costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG, which was completed in the third quarter of 2021, that were historically allocated to Generation but are presented
as part of continuing operations in Exelon’s results as these costs do not qualify as expenses of the discontinued operations per the accounting rules.
(c)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation, which are recorded in Operating and maintenance expense.
(d)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.
(e)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 2022 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 purpose of separation
and holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation and discontinued operations.
In connection with the separation, Exelon incurred separation costs impacting continuing operations of $24 million and $4
million on a pre-tax basis for the three months ended March 31, 2022 and March 31, 2021, respectively, which are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of 2022 are not 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 separation, and employee-related severance costs.
Distribution 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 financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
For 2022, the following total increases were included in ComEd’s and BGE's electric transmission formula rate update. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Registrant
Initial
Revenue Requirement Increase
Annual Reconciliation Decrease
Total Revenue Requirement Increase
Allowed Return on Rate Base
Allowed ROE
ComEd
$
24
$
(24)
$
—
8.11
%
11.50
%
BGE
25
(4)
16
7.30
%
10.50
%
Other
Key Business Drivers and Management Strategies
The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the Registrants' combined 2021 Form 10-K and Note 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.
Legislative and Regulatory Developments
Infrastructure Investment and Jobs Act
On November
15, 2021, President Biden signed the $1.2 trillion Infrastructure Investment and Jobs Act (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 in the process of 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 analyzing 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.
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. At March 31, 2022, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2021 except for critical accounting policies and estimates that relate to Generation, which are no longer applicable to the Registrants. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the
Registrants' 2021 Form 10-K for further information.
Three
Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net incomedecreased by $9 million as compared to the same period in 2021, primarily due to the voluntary customer refund related to the ICC investigation of matters identified in the Deferred Prosecution Agreement, partially offset by increases in electric distribution formula rate earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates). See Note 12 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.
The changes in Operating revenues consisted
of the following:
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of revenue decoupling mechanisms implemented pursuant to FEJA.
Distribution Revenue. EIMA and FEJA 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. Electric 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. Electric distribution revenue increased for the three months ended March 31, 2022 as compared to the
same period in 2021,
due to the impact of higher rate base, higher allowed ROE due to an increase in treasury rates, and 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. Transmission revenue increased for the three months ended March 31, 2022 as compared to the same periods in 2021 primarily due to the impact of higher rate base and higher fully recoverable costs.
Energy Efficiency Revenue. 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. Energy efficiency revenue increased for the three months ended March 31, 2022 as compared to the same period in 2021, 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 remained relatively the same for the three months ended March 31, 2022 as compared to the same period in 2021.
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, Energy Transition Assistance Charge ("ETAC"), and costs related to electricity, ZEC and REC procurement. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation 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 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, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd 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 presentation of ComEd's revenue disaggregation.
The
increase of $111 million for the three months ended March 31, 2022 compared to the same period in 2021, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.
Pension and non-pension postretirement benefits expense
(7)
Labor, other benefits, contracting and materials
2
BSC
costs
14
Other(a)
21
31
Regulatory required programs(b)
4
Total
increase
$
35
__________
(a)The increase is primarily due to the voluntary customer refund 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.
(b)ComEd 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 a rider mechanism.
The
changes in Depreciation and amortization expense consisted of the following:
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset
Taxes other than income taxes increased
by $21 million for the three months ended March 31, 2022 compared to the same period in 2021, primarily due to taxes related to ETAC, which is recovered through Operating revenues.
Effective income tax rates were 21.7% and 16.5% for the three months ended March 31, 2022 and 2021, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income increased by $39 million, primarily due to increases in electric and gas distribution rates, and volume.
The
changes in Operating revenues consisted of the following:
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 March 31, 2022 compared to the same period in 2021, Operating revenues related to weather decreased by the impact of unfavorable weather conditions in PECO'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 30-year period
in PECO's service territory. The changes in heating and cooling degree-days in
PECO’s service territory for the three months ended March 31, 2022 compared to the same period in 2021 and normal weather consisted of the following:
Three
Months Ended March 31,
% Change
PECO Service Territory
2022
2021
Normal
2022 vs. 2021
2022 vs. Normal
Heating
Degree-Days
2,228
2,302
2,416
(3.2)
%
(7.8)
%
Cooling Degree-Days
1
5
1
(80.0)
%
—
%
Volume. Electric
volume, exclusive of the effects of weather, for the three months ended March 31, 2022, compared to the same period in 2021, increased on a net basis due to an increase in overall usage for customers further increased by customer growth. Natural gas volume for the three months ended March 31, 2022 compared to the same period in 2021, increased due to retail load growth.
Electric
Retail Deliveries to Customers (in GWhs)
Three Months Ended March 31,
% Change
Weather -
Normal
% Change(b)
2022
2021
Residential
3,758
3,767
(0.2)
%
1.1
%
Small
commercial & industrial
1,937
1,881
3.0
%
3.4
%
Large commercial & industrial
3,332
3,272
1.8
%
1.9
%
Public
authorities & electric railroads
182
149
22.1
%
22.4
%
Total electric retail deliveries(a)
9,209
9,069
1.5
%
2.2
%
As
of March 31,
Number of Electric Customers
2022
2021
Residential
1,521,255
1,512,255
Small commercial & industrial
155,485
154,637
Large commercial & industrial
3,102
3,109
Public
authorities & electric railroads
10,342
10,237
Total
1,690,184
1,680,238
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation 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.
Natural
Gas Deliveries to Customers (in mmcf)
Three Months Ended March 31,
% Change
Weather -
Normal
% Change(b)
2022
2021
Residential
20,837
20,674
0.8
%
4.3
%
Small
commercial & industrial
10,546
10,170
3.7
%
5.8
%
Large commercial & industrial
10
7
42.9
%
10.2
%
Transportation
7,639
7,650
(0.1)
%
0.7
%
Total
natural gas retail deliveries(a)
39,032
38,501
1.4
%
4.0
%
As
of March 31,
Number of Natural Gas Customers
2022
2021
Residential
499,188
493,857
Small commercial & industrial
44,959
44,604
Large commercial & industrial
5
5
Transportation
664
685
Total
544,816
539,151
__________
(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 months
ended March 31, 2022 compared to the same period in 2021 increased primarily due to an increase in electric and gas distribution rates charged to customers.
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.
Other revenue primarily includes revenue related to late payment charges. Other revenues for the three months ended March 31, 2022 compared to the same period in 2021, remained relatively consistent.
Regulatory Required Programs represents revenues 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. 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 PECO 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 or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO 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 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 Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The increase of $91 million for the three months ended March 31, 2022 compared to the same period in 2021, respectively, 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:
Interest expense, net increased $3 million for the three months ended March 31, 2022 compared to the same period in 2021, primarily due to the issuance of debt in 2021.
Effective income tax rates were 6.4% and 5.6% for the three months ended March
31, 2022 and 2021 respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Three
Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income decreased $11 million primarily due to an increase in depreciation expense and credit loss expense, partially offset by favorable impacts of the multi-year plans. See Note 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.
The changes in Operating revenues consisted of the following:
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.
Distribution Revenue increased for the three months ended March
31, 2022,compared to the same period in 2021, 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 capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to the 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. Other revenue increased
for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to an increase in late fees charged to customers.
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 customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and 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 5 — Segment Information of the Combined Notes to Consolidated Financial
Statements for the presentation of BGE's revenue disaggregation.
The increase of $123 million for the three months ended March 31, 2022 compared to the same period in 2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
(a)Depreciation and amortization increased primarily due
to ongoing capital expenditures.
Effective income tax rateswere 4.3% and (6.6)% for the three months ended March 31, 2022 and 2021, respectively. The change is primarily due to decreases in the multi-year plans' accelerated income tax benefits in 2022 as compared to 2021. See Note 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.
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, 2022 compared to the same period in 2021. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Three
Months Ended March 31,
Favorable (Unfavorable) Variance
2022
2021
PHI
$
130
$
128
$
2
Pepco
46
59
(13)
DPL
56
56
—
ACE
26
14
12
Other(a)
2
(1)
3
_________
(a)Primarily
includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net Income increased by $2 million primarily due to favorable impacts as a result of Pepco's Maryland and District of Columbia multi-year plans and higher electric distribution rates at DPL and ACE, partially offset by an increase in storm costs and depreciation expense.
Three
Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021.Net income decreased $13 million primarily due to an increase in storm costs, depreciation expense, and credit loss expense, partially offset by the favorable impacts of the Maryland and District of Columbia multi-year plans.
The changes in Operating revenues consisted of the following:
Revenue Decoupling. The demand for electricity is affected by weather and customer 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 bill stabilization adjustment (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
2022
2021
Residential
846,258
835,415
Small commercial
& industrial
54,509
53,738
Large commercial & industrial
22,620
22,492
Public authorities & electric railroads
184
174
Total
923,571
911,819
Distribution
Revenue increased for the three months ended March 31, 2022 compared to the same period in 2021 primarily due to favorable impacts of the Maryland and District of Columbia 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 capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to increases in underlying costs.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
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 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 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 Pepco 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, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. 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 the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The increase of $47 million for the three months ended March 31, 2022 compared to the same period in 2021, 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 following:
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates
were (4.5)% and 9.2% for the three months ended March 31, 2022 and 2021, respectively. The change is primarily due to the acceleration of certain income tax benefits as a result of the Maryland and District of Columbia multi-year plans. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statement for additional information on the three-year electric 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.
Revenue
Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Weather. The demand for electricity and natural gas in Delaware 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 March 31, 2022 compared to the same period in 2021, Operating revenues related to weather remained consistent.
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 Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three months ended March 31, 2022 compared to same period in 2021 and normal weather consisted of the following:
Three
Months Ended March 31,
% Change
Delaware Electric Service Territory
2022
2021
Normal
2022 vs. 2021
2022 vs. Normal
Heating
Degree-Days
2,355
2,358
2,480
(0.1)
%
(5.0)
%
Cooling Degree-Days
3
3
—
—
%
—
%
Three
Months Ended March 31,
% Change
Delaware Natural Gas Service Territory
2022
2021
Normal
2022 vs. 2021
2022 vs. Normal
Heating
Degree-Days
2,355
2,358
2,500
(0.1)
%
(5.8)
%
Volume, exclusive of the effects of weather, increased for the three months ended March 31, 2022 compared to the same period in 2021 primarily due to customer growth and usage.
Electric
Retail Deliveries to Delaware Customers (in GWhs)
Three Months Ended March 31,
% Change
Weather - Normal
% Change(b)
2022
2021
Residential
895
854
4.8
%
4.2
%
Small
commercial & industrial
370
342
8.2
%
7.7
%
Large commercial & industrial
765
689
11.0
%
11.0
%
Public
authorities & electric railroads
9
9
—
%
5.3
%
Total electric retail deliveries(a)
2,039
1,894
7.7
%
7.3
%
As
of March 31,
Number of Total Electric Customers (Maryland and Delaware)
2022
2021
Residential
478,009
473,917
Small commercial & industrial
63,296
62,647
Large commercial & industrial
1,221
1,208
Public
authorities & electric railroads
603
608
Total
543,129
538,380
_________
(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 delivery volumes assuming normalized weather based on
the historical 20-year average.
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)
(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 the three months ended March 31, 2022 compared to the same period in 2021 primarily due to higher electric distribution rates in Maryland that became effective in March 2022, higher Distribution System Improvement Charge (DSIC) rates in Delaware that became effective in January 2022, and higher approved electric distribution rates in Delaware that became effective in September 2021.
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. Transmission revenue increased for the three months ended March 31, 2022, compared to the same period in 2021,primarily due to increases in underlying costs.
Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency 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 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 Operating 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 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 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 Purchased power and fuel expense. DPL recovers electricity and REC 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 the presentation of DPL's revenue disaggregation.
The increase of $33 million for the three months ended March 31, 2022, compared
to the same period in 2021, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rateswere 6.7%
and 8.2% for the three months ended March 31, 2022 and 2021, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Three
Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income increased $12 million primarily due to increases in distribution rates.
The changes in Operating revenues consisted of the following:
Revenue Decoupling. The demand for electricity is affected by weather and 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 Conservation Incentive Program (CIP) which became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case.
The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
Weather. Prior to the third quarter of 2021, the demand for electricity was affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the three months ended March 31, 2022 compared
to the same period in 2021, Operating revenues related to weather increased due to the absence of impacts in the first quarter of 2022 as a result of the CIP.
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 ACE’s
service territory. The changes in heating and cooling degree days in ACE’s service territory for the three months ended March 31, 2022 compared to same period in 2021 and normal weather consisted of the following:
Three
Months Ended March 31,
Normal
% Change
Heating and Cooling Degree-Days
2022
2021
2022 vs. 2021
2022 vs. Normal
Heating
Degree-Days
2,436
2,348
2,454
3.7
%
(0.7)
%
Cooling Degree-Days
2
4
1
(50.0)
%
100.0
%
Volume,exclusive of the effects of weather, increased for the three months ended March 31, 2022 compared to the same period in 2021, due to the absence of impacts in the first quarter of 2022 as a result of the CIP.
Electric
Retail Deliveries to Customers (in GWhs)
Three Months Ended March 31,
% Change
Weather - Normal % Change(b)
2022
2021
Residential
918
928
(1.1)
%
(2.3)
%
Small
commercial & industrial
339
305
11.1
%
9.7
%
Large commercial & industrial
703
716
(1.8)
%
(2.4)
%
Public
authorities & electric railroads
14
13
7.7
%
6.2
%
Total electric retail deliveries(a)
1,974
1,962
0.6
%
(0.4)
%
As
of March 31,
Number of Electric Customers
2022
2021
Residential
500,511
498,396
Small commercial & industrial
62,124
61,771
Large commercial & industrial
3,124
3,267
Public
authorities & electric railroads
724
704
Total
566,483
564,138
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on
the historical 20-year average.
Distribution Revenue increased for the three months ended March 31, 2022 compared to the same period in 2021 due to higher distribution rates that become effective in January 2022.
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. Transmission revenue increased for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to increases in capital investment and underlying costs.
Other Revenue
includes rental revenue, service connection fees, and mutual assistance revenues.
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 Bonds, and BGS procurement and administrative costs. 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 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 presentation of ACE's revenue disaggregation.
The increase of $21 million for the three months ended March 31, 2022 compared to the same period in 2021, respectively, 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 following:
(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 Depreciation and amortizationexpense consisted of the following:
(a)Depreciation
and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were 3.7% and 0.0% for the three months ended March 31, 2022 and 2021, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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 credit facilities with aggregate bank commitments of $4.0 billion. 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 and Cash Requirements”
section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Cash flows related to Constellation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for all periods presented. The Exelon Consolidated Statement of Cash Flows for the three months ended March 31, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the three months ended March 31, 2021 includes three months of cash flows from Generation. This is the primary reason
for the changes in cash flows as shown in the tables unless otherwise noted below.
Cash Flows from Operating Activities
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, and their ability to achieve operating cost reductions.
See Note 3 — Regulatory Matters of the Exelon 2021 Form 10-K and Note 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements
for additional information on regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the change in cash flows from operating activities for the three months ended March 31, 2022 and 2021 by Registrant:
Increase
(decrease) in cash flows from operating activities
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Net income (loss)
$
862
$
(9)
$
39
$
(11)
$
2
$
(13)
$
—
$
12
Adjustments
to reconcile net income to cash:
Non-cash operating activities
69
20
17
70
66
37
17
11
Option
premiums (paid), net
(55)
—
—
—
—
—
—
—
Collateral received, net
869
38
—
—
—
—
—
—
Income
taxes
(36)
21
(3)
13
2
(1)
(4)
(1)
Pension and non-pension postretirement benefit contributions
(37)
(5)
4
9
(31)
—
(1)
(4)
Changes
in working capital and other noncurrent assets and liabilities
1,371
53
(41)
67
(16)
—
31
(28)
Increase (decrease) in cash flows
from operating activities
$
3,043
$
118
$
16
$
148
$
23
$
23
$
43
$
(10)
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. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for the three months ended March 31, 2022 and 2021 were as follows:
•See Note 14 — 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.
•Changes
in collateral depended upon whether Generation was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets.
•See Note 7 — 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 working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $88 million and for Generation total $1,283
million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. See Note 6 — Accounts Receivable of the Exelon 2021 Form 10-K and the Collection of DPP discussion below for additional information.
The following table provides a summary of the change in cash flows from investing activities for the three months ended March 31, 2022 and 2021
by Registrant:
(Decrease)
increase in cash flows from investing activities
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Capital expenditures
$
218
$
(4)
$
(49)
$
33
$
47
$
2
$
9
$
36
Investment
in NDT fund sales, net
3
—
—
—
—
—
—
—
Collection of DPP
(1,405)
—
—
—
—
—
—
—
Proceeds
from sales of assets and businesses
(664)
—
—
—
—
—
—
—
Changes in intercompany money pool
—
—
48
—
—
—
—
—
Other
investing activities
(66)
—
1
1
1
—
1
—
(Decrease) increase in cash flows from investing activities
$
(1,914)
$
(4)
$
—
$
34
$
48
$
2
$
10
$
36
Significant
investing cash flow impacts for the Registrants for three months ended March 31, 2022 and 2021 were as follows:
•Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation.
•Collection of DPP relates to the revolving accounts receivable financing agreement which Generation entered into in April of 2020. See Note 6
— Accounts Receivable of the Exelon 2021 Form 10-K for additional information on the transaction and the DPP, including the $400 million of additional funding received in February and March of 2021.
•Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of Generation's solar business in 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Exelon 2021 Form 10-K 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.
Cash Flows from Financing Activities
The following table provides a summary of
the change in cash flows from financing activities for the three months ended March 31, 2022 and 2021 by Registrant:
Increase
(decrease) in cash flows from financing activities
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Changes in short-term borrowings, net
$
(997)
$
188
$
—
$
(36)
$
(100)
$
(140)
$
(3)
$
43
Long-term
debt, net
2,669
50
(375)
—
119
250
—
(131)
Changes in intercompany money pool
—
—
105
—
36
—
—
—
Dividends
paid on common stock
42
(17)
(15)
(2)
—
(14)
(1)
(5)
Distributions to member
—
—
—
—
(21)
—
—
—
Contributions
from(to) parent/member
—
(31)
227
—
144
249
24
(130)
Transfer of cash, restricted cash, and cash equivalents to Constellation
(2,594)
—
—
—
—
—
—
—
Other
financing activities
(38)
(1)
3
(1)
(4)
(4)
—
—
Increase (decrease) in cash flows from financing activities
$
(918)
$
189
$
(55)
$
(39)
$
174
$
341
$
20
$
(223)
Significant
financing cash flow impacts for the Registrants for the three months ended March 31, 2022 and 2021 were as follows:
•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation.
•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 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 19 — Commitments and Contingenciesof the Exelon 2021 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.
•For the three months ended March 31, 2022, other financing activities primarily consists of debt issuance costs. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.
Debt
See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
During
the three months ended March 31, 2022, there were no long-term debt retirements or redemptions. However, as of May 9, 2022, the following long-term debt was retired and/or redeemed:
Quarterly
dividends declared by the Exelon Board of Directors during the three months ended March 31, 2022 and for the second quarter of 2022 were as follows:
(a)Exelon's
Board of Directors approved an updated dividend policy for 2022. The 2022 quarterly dividend will be $0.3375 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 $4.0 billion in aggregate total commitments of which $3.7 billion was available to support additional commercial paper as of March 31, 2022, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the three months ended
March 31, 2022 to fund their short-term liquidity needs, when necessary. On February 1, 2022, Exelon Corporate and the Utility Registrants each entered into a new 5-year revolving credit facility that replaced its existing syndicated 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 2021 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements.
Pursuant to the Separation Agreement between Exelon and Constellation, Exelon made a cash payment of $1.75 billion to Generation on January 31, 2022. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation.
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 March 31, 2022 and available credit facility capacity prior to any incremental collateral at March 31, 2022:
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd
$
40
$
—
$
998
PECO
2
39
600
BGE
2
62
350
Pepco
2
—
300
DPL
2
16
300
ACE
1
—
300
_________
(a)Represents
incremental collateral related to natural gas procurement contracts.
Capital Expenditure Spending
As of March 31, 2022, the most recent estimates of capital expenditures for plant additions and improvements for 2022 are as follows:
(In millions)
Transmission
Distribution
Gas
Total(a)
Exelon
N/A
N/A
N/A
$
6,900
ComEd
475
2,000
N/A
2,475
PECO
200
800
325
1,325
BGE
250
500
475
1,225
PHI
575
1,200
75
1,850
Pepco
275
675
N/A
950
DPL
125
250
75
450
ACE
175
275
N/A
450
__________
(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.
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 (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 levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Post-separation, Exelon's estimated annual qualified pension contributions will be approximately $313 million in 2022. In connection with the separation, additional qualified pension contributions of $207 million and $33 million were completed on February 1, 2022 and March 2, 2022, respectively. 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).
Exelon Corporate, ComEd,
and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meet their 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.
See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term
borrowing activity.
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 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for ComEd, PECO, BGE, and DPL did not change for the three months ended March 31, 2022. On January 14, 2022, Fitch lowered Exelon Corporate's long-term and senior unsecured ratings from BBB+ to BBB and affirmed the short-term rating of F2. In addition, Fitch upgraded Pepco, ACE, and PHI's long-term rating from BBB to BBB+ and upgraded Pepco and ACE's
senior secured rating from A- to A.
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. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of March 31, 2022, are presented in the following table. Pepco, ACE, and DPL had no activity within the PHI intercompany money pool during the three months ended March 31, 2022.
Exelon and the Utility Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the
SEC, that will expire in August 2022. 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
The Utility Registrants are required
to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
(a)On
November 18, 2021, ComEd received approval from the ICC for $2 billion in new money long-term debt financing authority with an effective date of January 1, 2022.
(b)On December 2, 2021, PECO received approval from the PAPUC for $2.5 billion in new long-term debt financing authority with an effective date of January 1, 2022.
(c)ACE is currently in the process of renewing its long-term financing authority with the NJBPU and expects approval by August 1, 2022.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Registrants hold commodity and financial instruments that are exposed 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 shared by the remaining participants. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated
Financial Statements for a 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 15 — Retirement Benefits of the Exelon 2021 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 variable-rate debt to manage interest rate exposure. See Note 10 — Debt and Credit Agreements of the 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 utilized to reduce 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 through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. Risk management issues are reported to Exelon’s Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of Directors.
Commodity Price Risk
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 purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity and natural gas.
ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO,
BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE, and DPL also have executed derivative natural gas contracts, which either qualify for NPNS or have no mark-to-market balances because the derivatives are index priced, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements.
For additional information on these contracts, see Note 9 — Derivative Financial Instruments and Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes
to Consolidated Financial Statements.
The following table presents the maturity and source of fair value for Exelon’s and ComEd’s mark-to-market commodity contract liabilities. These liabilities are associated with ComEd’s floating-to-fixed energy swap
contracts with unaffiliated suppliers. The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market liabilities.
Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 11 — 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.
Maturities
Within
Total Fair Value
2022
2023
2024
2025
2026
2027 and Beyond
Prices based on model or other valuation methods (Level 3)
$
(1)
$
(8)
$
(18)
$
(18)
$
(18)
$
(81)
$
(144)
ITEM 4. CONTROLS
AND PROCEDURES
During the first quarter of 2022, each of the 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 the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that 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 March 31, 2022, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The 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 were no changes in internal control
over financial reporting during the first quarter of 2022 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 2021 Form 10-K and (b) Notes 3 — Regulatory Matters and 12 — Commitments and Contingencies
of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
ITEM 1A. RISK FACTORS
Risks Related to All Registrants
At March 31, 2022, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2021 Form 10-K in ITEM 1A. RISK FACTORS.
Certain
of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the Commission upon request.
Inline XBRL
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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022 filed by the following officers for the following companies:
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022 filed by the following officers for the following companies:
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.
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.
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.
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.
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.
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.
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.
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.
