(Dollars in millions, unless otherwise noted)
Executive Overview
We are a supplier of clean energy. Our generating capacity includes primarily
nuclear, wind, solar, natural gas and hydroelectric assets. Through our
integrated business operations, we sell electricity, natural gas, and other
energy-related products and sustainable solutions to various types of customers,
including distribution utilities, municipalities, cooperatives, and commercial,
industrial, governmental, and residential customers in markets across multiple
geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New
York, ERCOT and Other Power Regions.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth our GAAP consolidated
Net (loss) income for the three and nine months ended September 30, 2022
compared to the same period in 2021. For additional information regarding the
financial results for the three and nine months ended September 30, 2022 and
2021 see the discussions of Results of Operations below.
Three Months Ended September Favorable Favorable
30, (Unfavorable) Nine Months Ended September 30, (Unfavorable)
2022 2021 Variance 2022 2021 Variance
GAAP Net (loss)
income $ (188) $ 607 $ (795) $ (194) $ (247) $ 53
Adjusted EBITDA (non-GAAP). In analyzing and planning for our business, we
supplement our use of GAAP net income with Adjusted EBITDA (non-GAAP) as a
performance measure. Adjusted EBITDA (non-GAAP) reflects an additional way of
viewing our business that, when viewed with our GAAP results and the
accompanying reconciliation to GAAP net income included in the table below, may
provide a more complete understanding of factors and trends affecting our
business. Adjusted EBITDA (non-GAAP) should not be relied upon to the exclusion
of GAAP financial measures and is, by definition, an incomplete understanding of
our business, and must be considered in conjunction with GAAP measures. In
addition, Adjusted EBITDA (non-GAAP) is neither a standardized financial
measure, nor 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.
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The following table provides a reconciliation between Net (loss) income
attributable to common shareholders as determined in accordance with GAAP and
Adjusted EBITDA (non-GAAP) for the three and nine months ended September 30,
2022 compared to the same period in 2021.
Three Months Ended Nine Months Ended
September 30, September 30,
2022 2021 2022 2021
Net (Loss) Income Attributable to Common Shareholders $ (188)
$ 607 $ (194) $ (247)
Income Taxes(a) (149) 177 (472) 108
Depreciation and Amortization(b) 262 866 818 2,735
Interest Expense, Net 75 77 187 225
Unrealized Loss (Gain) on Fair Value Adjustments(c) 550 (614) 645 (1,191)
Asset Impairments(d) - 45 - 537
Plant Retirements and Divestitures(e) 5 (62) (3) (15)
Decommissioning-Related Activities(f) 88 (130) 1,126 (1,014)
Pension & OPEB Non-Service Credits (27) (11) (85) (36)
Separation Costs(g) 30 16 99 25
COVID-19 Direct Costs(h) - 5 - 24
Acquisition-Related Costs(i) - 11 - 21
ERP System Implementation Costs(j) 5 5 16 10
Change in Environmental Liabilities 3 5 12 7
Cost Management Program - 4 - 9
Prior Merger Commitment(k) (50) - (50) -
Noncontrolling Interests(l) (12) (34) (37) (40)
Adjusted EBITDA (non-GAAP) $ 592 $ 967 $ 2,062 $ 1,158
__________
(a)In 2022, includes amounts contractually owed to Exelon under the tax matters
agreement reflected in Other, net.
(b)In 2021, includes the accelerated depreciation associated with early plant
retirements.
(c)Includes mark-to-market on economic hedges and fair value adjustments related
to gas imbalances and equity investments.
(d)Reflects an impairment of a wind project in the third quarter of 2021, and
nine months ended, September 30, 2021 also includes an impairment in the New
England asset group, and an impairment recorded as a result of the sale of the
Albany Green Energy biomass facility.
(e)In 2021, primarily reflects accelerated nuclear fuel amortization for Byron
and Dresden, partially offset by a gain on sale of our solar business which
occurred in the first quarter of 2021 and a reversal of one-time charges
resulting from the reversal of the previous decision to retire Byron and
Dresden.
(f)Reflects all gains and losses associated with NDTs, ARO accretion, ARO
remeasurement, and any earnings neutral impacts of contractual offset for
Regulatory Agreement Units.
(g)Represents certain incremental costs related to the separation
(system-related costs, third-party costs paid to advisors, consultants, lawyers,
and other experts assisting in the separation), including a portion of the
amounts billed to us pursuant to the TSA.
(h)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.
(i)Reflects costs related to the acquisition of EDF's interest in CENG, which
was completed in the third quarter of 2021.
(j)Reflects costs related to a multi-year Enterprise Resource Program (ERP)
system implementation.
(k)Reversal of a charge related to a prior 2012 merger commitment.
(l)Reflects elimination from results for the noncontrolling interests related to
certain adjustments. In 2022, primarily relates to CRP and in 2021, primarily
relates to CENG and the noncontrolling interest portion of a wind project
impairment recognized within CRP.
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Results of Operations
Three Months Ended September Favorable Nine Months Ended September Favorable
30, (Unfavorable) 30, (Unfavorable)
2022 2021 Variance 2022 2021 Variance
Operating revenues $ 6,051 $ 4,406 $ 1,645 $ 17,107 $ 14,117 $ 2,990
Operating expenses
Purchased power and fuel 4,695 1,546 (3,149) 11,754 8,103 (3,651)
Operating and maintenance 989 938 (51) 3,466 3,413 (53)
Depreciation and amortization 262 866 604 818 2,735 1,917
Taxes other than income taxes 145 115 (30) 415 354 (61)
Total operating expenses 6,091 3,465 (2,626) 16,453 14,605 (1,848)
(Loss) gain on sales of assets and
businesses (1) 65 (66) 13 144 (157)
Operating (loss) income (41) 1,006 (1,047) 667 (344) 1,011
Other income and (deductions)
Interest expense, net (75) (77) 2 (187) (225) 38
Other, net (196) (115) (81) (1,169) 561 (1,730)
Total other income and (deductions) (271) (192) (79) (1,356) 336
(1,692)
(Loss) income before income taxes (312) 814 (1,126) (689) (8) (681)
Income taxes (123) 177 300 (504) 108 (612)
Equity in losses of unconsolidated
affiliates (4) (4) - (10) (6) (4)
Net (loss) income (193) 633 (826) (195) (122) (73)
Net (loss) income attributable to
noncontrolling interests (5) 26 (31) (1) 125
(126)
Net (loss) income attributable to
common shareholders $ (188) $ 607 $ (795) $ (194) $ (247) 53
Three Months Ended September 30, 2022 Compared to Three Months Ended September
30, 2021. Net (loss) income attributable to common shareholders was unfavorable
by $795 million primarily due to:
•Unfavorable mark-to-market activity;
•Unfavorable net realized and unrealized NDT activity;
•Higher labor, contracting and materials;
•Lower capacity revenues; and
•Unfavorable portfolio optimization activity
The unfavorable items were partially offset by:
•The absence of accelerated depreciation and amortization associated with our
previous decision in the third quarter of 2020 to early retire Byron and Dresden
nuclear facilities in 2021, a decision which was reversed on September 15, 2021
and the absence of the reversal of charges recorded in the third quarter of 2021
associated with the reversal of the previous decision;
•Impact of our annual update to the nuclear ARO for Non-Regulatory Agreement
Units;
•Favorable impact of net realized and unrealized CTV investment activity; and
•The reversal of a charge related to a 2012 prior merger commitment
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Nine months ended September 30, 2022 Compared to Nine months ended September 30,
2021. Net loss attributable to common shareholders was favorable by $53 million
primarily due to:
•The absence of accelerated depreciation and amortization associated with our
previous decision in the third quarter of 2020 to early retire Byron and Dresden
nuclear facilities in 2021, a decision which was reversed on September 15, 2021,
the absence of the reversal of charges recorded in the third quarter of 2021
associated with the reversal of the previous decision, and our decision in the
third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024;
•The absence of impacts from the February 2021 extreme cold weather event;
•The absence of impairments of the New England asset group, the Albany Green
Energy biomass facility, and a wind project;
•Higher realized energy prices;
•Impact of our annual update to the nuclear ARO for Non-Regulatory Agreement
Units;
•Lower nuclear fuel costs due to the absence of accelerated amortization of
nuclear fuel and lower prices; and
•The reversal of a charge related to a 2012 prior merger commitment
The favorable items were partially offset by:
•Unfavorable mark-to-market activity;
•Unfavorable net realized and unrealized NDT activity;
•Lower capacity revenues;
•Higher labor, contracting and materials;
•Unfavorable impacts from nuclear outages;
•Higher separation costs; and
•The absence of a prior year gain on the sale of our solar business
Operating revenues. The basis for our reportable segments is the integrated
management of our electricity business that is located in different geographic
regions, and largely representative of the footprints of ISO/RTO and/or NERC
regions, which utilize multiple supply sources to provide electricity through
various distribution channels (wholesale and retail). Our hedging strategies and
risk metrics are also aligned with these same geographic regions. Our five
reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power
Regions. See Note 5 - Segment Information of the Combined Notes to Consolidated
Financial Statements for additional information on these reportable segments.
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The following business activities are not allocated to a region and are reported
under Other: natural gas, as well as other miscellaneous business activities
that are not significant to overall operating revenues or results of operations.
For the three and nine months ended September 30, 2022 compared to 2021,
Operating revenues by region were as follows:
Three Months Ended September Nine Months Ended September
30, 30,
2022 2021 Variance % Change(a) 2022 2021 Variance % Change(a)
Mid-Atlantic $ 1,659 $ 1,272 $ 387 30.4 % $ 3,967 $ 3,527 $ 440 12.5 %
Midwest 1,047 985 62 6.3 % 3,345 2,945 400 13.6 %
New York 423 455 (32) (7.0) % 1,178 1,173 5 0.4 %
ERCOT 490 358 132 36.9 % 1,210 890 320 36.0 %
Other Power Regions 1,936 1,260 676 53.7 % 5,189 3,729 1,460 39.2 %
Total electric revenues 5,555 4,330 1,225 28.3 % 14,889 12,264 2,625 21.4 %
Other 1,177 711 466 65.5 % 4,117 2,811 1,306 46.5 %
Mark-to-market losses (681) (635) (46) (1,899) (958) (941)
Total Operating revenues $ 6,051 $ 4,406 $ 1,645 37.3 % $ 17,107 $ 14,117 $ 2,990 21.2 %
__________
(a)% Change in mark-to-market is not a meaningful measure.
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Sales and Supply Sources. Our sales and supply sources by region are summarized
below:
Three Months Ended September 30, Nine Months Ended September 30,
Supply Source (GWhs) 2022 2021 Variance % Change 2022 2021 Variance % Change
Nuclear Generation(a)
Mid-Atlantic 13,540 13,753 (213) (1.5) % 39,272 40,203 (931) (2.3) %
Midwest 24,275 23,909 366 1.5 % 71,079 70,363 716 1.0 %
New York(b) 5,979 6,688 (709) (10.6) % 18,563 19,820 (1,257) (6.3) %
Total Nuclear Generation 43,794 44,350 (556) (1.3) % 128,914 130,386 (1,472) (1.1) %
Natural Gas, Oil, and
Renewables
Mid-Atlantic 230 491 (261) (53.2) % 1,573 1,675 (102) (6.1) %
Midwest 126 177 (51) (28.8) % 774 763 11 1.4 %
New York - - - - % - 1 (1) (100.0) %
ERCOT 4,987 4,670 317 6.8 % 10,873 10,250 623 6.1 %
Other Power Regions 2,401 2,409 (8) (0.3) % 7,179 7,641 (462) (6.0) %
Total Natural Gas, Oil, and
Renewables 7,744 7,747 (3) - % 20,399 20,330 69 0.3 %
Purchased Power
Mid-Atlantic 6,508 4,565 1,943 42.6 % 12,164 12,123 41 0.3 %
Midwest 74 77 (3) (3.9) % 425 386 39 10.1 %
ERCOT 705 595 110 18.5 % 2,855 2,626 229 8.7 %
Other Power Regions 13,869 13,585 284 2.1 % 39,964 38,778 1,186 3.1 %
Total Purchased Power 21,156 18,822 2,334 12.4 % 55,408 53,913 1,495 2.8 %
Total Supply/Sales by Region
Mid-Atlantic 20,278 18,809 1,469 7.8 % 53,009 54,001 (992) (1.8) %
Midwest 24,475 24,163 312 1.3 % 72,278 71,512 766 1.1 %
New York(b) 5,979 6,688 (709) (10.6) % 18,563 19,821 (1,258) (6.3) %
ERCOT 5,692 5,265 427 8.1 % 13,728 12,876 852 6.6 %
Other Power Regions 16,270 15,994 276 1.7 % 47,143 46,419 724 1.6 %
Total Supply/Sales by Region 72,694 70,919 1,775 2.5 % 204,721 204,629 92 - %
__________
(a)Includes the proportionate share of output where we have an undivided
ownership interest in jointly-owned generating plants. Includes the total output
for fully owned plants and the total output for CENG prior to the acquisition of
EDF's interest on August 6, 2021 as CENG was fully consolidated. See Note 2 -
Mergers, Acquisitions, and Dispositions of our 2021 Form 10-K for additional
information on our acquisition of EDF's interest in CENG.
(b)2021 values have been revised from those previously reported to correctly
reflect our 82% undivided ownership interest in Nine Mile Point Unit 2.
Nuclear Fleet Capacity Factor. The following table presents nuclear fleet
operating data for our plants, which reflects ownership percentage of stations
operated by us, excluding Salem, which is operated by PSEG. The nuclear fleet
capacity factor presented in the table is defined as the ratio of the actual
output of a plant over a period of time to its output if the plant had operated
at its net monthly mean capacity for that time period. We consider capacity
factor to be a useful measure to analyze the nuclear fleet performance between
periods. We have included the analysis below as a complement to the financial
information provided in accordance with GAAP. However, these measures are not a
presentation defined under GAAP and may not be comparable to other companies'
presentations or be more useful than the GAAP information provided elsewhere in
this report.
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Three Months Ended Nine Months Ended
September 30, September 30,
2022 2021 2022 2021
Nuclear fleet capacity factor(a) 96.4 % 97.7 % 94.5 % 95.3 %
Refueling outage days 5 22 147 172
Non-refueling outage days 26 - 51 10
__________
(a)Prior year capacity factor was previously reported as 96.0% and 95.0% for the
three and nine months ended September 30, 2021, respectively. The update
reflects a change to the ratio from using the full average annual mean capacity
to the net monthly mean capacity when calculating capacity factor. There is no
change to actual output and the full year capacity factor would be the same
under both methodologies.
ZEC Prices. We are compensated through state programs for the carbon-free
attributes for certain of our nuclear generation. ZEC programs are a significant
contributor to our total operating revenues. The following table includes the
average ZEC reference prices ($/MWh) for each of our major regions in which
state programs have been enacted. Prices reflect the weighted average price for
the various delivery periods within the three and nine months ended September
30, 2022 and 2021.
Three Months Ended September Nine Months Ended September
30, 30,
State (Region)(a) 2022 2021 Variance % Change 2022 2021 Variance % Change
New Jersey (Mid-Atlantic) $ 10.00 $ 10.00 $
- - % $ 10.00 $ 10.00 $ - - %
Illinois (Midwest)(b) 12.01 16.50 (4.49) (27.2) % 14.50 16.50 (2.00) (12.1) %
New York (New York) 21.38 21.38 - - % 21.38 20.78 0.60 2.9 %
__________
(a)See Note 7 - Early Plant Retirements of the Combined Notes to Consolidated
Financial Statements for additional information on the plants receiving payments
through state programs.
(b)Subject to a cap on total consideration to be received by us for each
delivery period. See Note 4 - Revenue from Contracts with Customers for
additional information.
Illinois CMC Price. The price received (paid) for each CMC is determined by the
IPA monthly and is based on the accepted CMC bid, less the sum of (a) monthly
weighted average PJM Busbar price, (b) ComEd zone capacity price and (c) any
federal tax credit or subsidy received and is subject to a customer protection
cap ($30.30 per MWh for initial delivery period June 1, 2022 through May 31,
2023). If the monthly CMC price per MWh calculation results in a net positive
value, ComEd will multiply that value by the delivered quantity and pay the
total to us. If the CMC price per MWh calculation results in a net negative
value, we will multiply this value by the delivered quantity and pay the net
value to ComEd. For the three and nine months ended September 30, 2022, the
average CMC price per MWh was a net negative value ($51.70) and ($51.85),
respectively. See Note 3 - Regulatory Matters of our 2021 Form 10-K for
additional information on the Illinois CMC program.
Capacity Prices. We participate in capacity auctions in each of our major
regions, except ERCOT which does not have a capacity market. We also incur
capacity costs associated with load served, which are factored into customer
sales prices. Capacity prices have a significant impact on our operating
revenues and purchased power and fuel expense. We report capacity on a net
monthly basis within each region in either Operating revenues or Purchased power
and fuel, depending on our net monthly position. The following tables present
the average capacity reference prices ($/MW Day) for each of our major regions.
Prices reflect the weighted averages for the various auction periods within the
three and nine months ended September 30, 2022 and 2021.
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Three Months Ended September Nine Months Ended September
30, 30,
Location (Region) 2022 2021 Variance % Change 2022 2021 Variance % Change
Eastern Mid-Atlantic Area
Council (Mid-Atlantic) $ 97.86 $ 165.73 $ (67.87) (41.0) % $ 135.57 $ 178.03 $ (42.46) (23.8) %
ComEd (Midwest) 68.96 195.55 (126.59) (64.7) % 139.29 191.42 (52.13) (27.2) %
Rest of State (New York) 108.22 164.40 (56.18) (34.2) % 89.67 98.47 (8.80) (8.9) %
Southeast New England
(Other) 126.67 154.37 (27.70) (17.9) % 142.06 166.76 (24.70) (14.8) %
Electricity Prices. As a producer and supplier of electricity, the price of
electricity has a significant impact on our operating revenues and purchased
power cost. We report the sale and purchase of electricity in the spot market on
a net hourly basis in either Operating revenues or Purchased power and fuel
expense within each region, depending on our net hourly position. The price of
electricity is impacted by several variables, including but not limited to, the
price of fuels, generation resources in the region, weather, on-going
competition, emerging technologies, as well as macroeconomic and regulatory
factors. The following table presents an average day-ahead around-the-clock
reference price ($/MWh) for the periods presented for each of our major regions
and does not necessarily reflect prices we ultimately realized.
Three Months Ended September Nine Months Ended September
30, 30,
Location (Region) 2022 2021 Variance % Change 2022 2021 Variance % Change
PJM West (Mid-Atlantic) $ 90.43 $ 41.81 $ 48.62 116.3 % $ 74.33 $ 33.78 $ 40.55 120.0 %
ComEd (Midwest) 81.99 39.70 42.29 106.5 % 62.90 31.87 31.03 97.4 %
Central (New York) 74.96 36.29 38.67 106.6 % 60.89 26.68 34.21 128.2 %
North (ERCOT) 97.58 39.18 58.40 149.1 % 68.47 193.18 (124.71) (64.6) %
Southeast Massachusetts
(Other)(a) 86.27 43.82 42.45 96.9 % 89.01 41.18 47.83 116.1 %
__________
(a)Reflects New England, which comprises the majority of the activity in the
Other region.
For the three and nine months ended September 30, 2022 compared to 2021, changes
in Operating revenues by region were approximately as follows:
Three Months Ended Nine Months Ended September
Variance % Change(a) September 30 Variance % Change(a) 30
Mid-Atlantic $ 387 30.4 % • favorable wholesale load $ 440 12.5 % • favorable retail load
revenue of $210 primarily revenue of $415 primarily
due to higher energy prices due to higher energy prices
and higher volumes • favorable wholesale load
• favorable retail load revenue of $100 primarily
revenue of $180 primarily due to higher energy prices
due to higher energy prices partially offset by lower
volumes; partially offset by
• unfavorable settled
economic hedges of ($60) due
to settled prices relative
to hedged prices
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Midwest 62 6.3 % • favorable retail load 400 13.6 % • favorable net wholesale
revenue of $120 primarily due load and generation revenue
to higher energy prices; of $460 primarily due to
partially offset by higher energy prices and
• unfavorable net wholesale higher volumes, partially
load and generation revenue offset by CMC program
of ($35) primarily due to activity and lower cleared
lower cleared capacity capacity volumes
volumes • favorable retail load
revenue of $220 primarily due
to higher energy prices;
partially offset by
• unfavorable settled
economic hedges of ($270) due
to settled prices relative to
hedged prices
New York (32) (7.0) % • unfavorable settled 5 0.4 % • favorable retail load
economic hedges of ($125) due revenue of $235 primarily due
to settled prices relative to to higher energy prices and
hedged prices; partially higher volumes
offset by • favorable generation
• favorable retail load revenue of $115 primarily due
revenue of $95 primarily due to higher energy prices
to higher energy prices and partially offset by lower
higher volumes nuclear generation due to an
increase in outage days;
partially offset by
• unfavorable settled
economic hedges of ($325) due
to settled prices relative to
hedged prices
ERCOT 132 36.9 % • favorable retail load 320 36.0 % • favorable settled economic
revenue of $110 primarily due hedges of $335 due to settled
to higher energy prices and prices relative to hedged
higher volumes prices
• favorable retail load
revenue of $70 primarily due
to higher volumes partially
offset by lower energy prices
relative to the prior year
due to the February 2021
extreme cold weather event;
partially offset by
• unfavorable wholesale load
revenue of ($65) primarily
due to lower energy prices
relative to the prior year
due to the February 2021
extreme cold weather event
Other Power Regions 676 53.7 % • favorable wholesale load 1,460 39.2 % • favorable wholesale load
revenue of $340 primarily due revenue of $590 primarily due
to higher energy prices and to higher energy prices and
higher volumes higher volumes
• favorable settled economic • favorable settled economic
hedges of $180 due to settled hedges of $535 due to settled
prices relative to hedged prices relative to hedged
prices prices
• favorable retail load • favorable retail load
revenue of $135 primarily due revenue of $295 primarily due
to higher energy prices to higher energy prices and
higher volumes
Other 466 65.5 % • favorable gas revenue, 1,306 46.5 % • favorable gas revenue,
including settled financial including settled financial
hedges, of $510 primarily due hedges, of $1,360 primarily
to higher gas prices due to higher gas prices
• favorable energy revenue of
$190 primarily due to higher
energy prices; partially
offset by
• unfavorable impact due to
the absence of the customer
pass through impact of LDC
and pipeline penalties due to
the February 2021 extreme
cold weather event of ($220)
Mark-to-market(b) (46) • losses on economic hedging (941) • losses on economic hedging
activities of ($681) in 2022 activities of ($1,899) in
compared to losses of ($635) 2022 compared to losses of
in 2021 ($958) in 2021
Total $ 1,645 37.3 % $ 2,990 34.6 %
__________
(a)% Change in mark-to-market is not a meaningful measure.
(b)See Note 12 - Derivative Financial Instruments of the Combined Notes to
Consolidated Financial Statements for additional information on mark-to-market
gains and losses.
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Purchased power and fuel. See Operating revenues above for discussion of our
reportable segments and hedging strategies and for supplemental statistical
data, including supply sources by region, nuclear fleet capacity factor,
capacity prices, and electricity prices.
The following business activities are not allocated to a region and are reported
under Other: natural gas, as well as other miscellaneous business activities
that are not significant to overall purchased power and fuel expense or results
of operations, and accelerated nuclear fuel amortization associated with nuclear
decommissioning.
For the three and nine months ended September 30, 2022 compared to 2021,
Purchased power and fuel by region were as follows:
Three Months Ended September Nine Months Ended September
30, 30,
2022 2021 Variance % Change(a) 2022 2021 Variance % Change(a)
Mid-Atlantic $ 1,104 $ 702 $ (402) (57.3) % $ 2,355 $ 1,815 $ (540) (29.8) %
Midwest 475 330 (145) (43.9) % 1,335 930 (405) (43.5) %
New York 156 109 (47) (43.1) % 351 293 (58) (19.8) %
ERCOT 424 179 (245) (136.9) % 975 1,812 837 46.2 %
Other Power Regions 1,679 1,049 (630) (60.1) % 4,479 3,165 (1,314) (41.5) %
Total electric purchased
power and fuel 3,838 2,369 (1,469) (62.0) % 9,495 8,015 (1,480) (18.5) %
Other 1,014 566 (448) (79.2) % 3,587 2,288 (1,299) (56.8) %
Mark-to-market gains (157) (1,389) (1,232) (1,328) (2,200) (872)
Total purchased power and
fuel $ 4,695 $ 1,546 $ (3,149) (203.7) % $ 11,754 $ 8,103 $ (3,651) (45.1) %
__________
(a)% Change in mark-to-market is not a meaningful measure.
For the three and nine months ended September 30, 2022 compared to 2021, changes
in Purchased power and fuel by region were approximately as follows:
Three Months Ended September Nine Months Ended September
Variance % Change(a) 30 Variance % Change(a) 30
Mid-Atlantic $ (402) (57.3) % • unfavorable purchased $ (540) (29.8) % • unfavorable purchased power
power and net capacity and net capacity impact of
impact of ($400) primarily ($565) primarily due to
due to higher energy prices, higher energy prices, lower
lower capacity prices earned nuclear generation, and lower
and lower nuclear generation capacity prices earned;
partially offset by
• favorable settlement of
economic hedges of $40 due to
settled prices relative to
hedged prices
Midwest (145) (43.9) % • unfavorable purchased (405) (43.5) % • unfavorable purchased power
power and net capacity and net capacity impact of
impact of ($160) primarily ($485) primarily due to
due to higher energy prices higher energy prices, higher
and lower capacity prices load, and lower capacity
earned prices earned; partially
offset by
• favorable nuclear fuel cost
of $80 primarily due to
accelerated amortization of
nuclear fuel in prior periods
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New York (47) (43.1) % • unfavorable purchased power (58) (19.8) % • unfavorable purchased power
and net capacity impact of and net capacity impact of
($40) primarily due to higher ($140) primarily due to higher
energy prices, higher load, energy prices, higher load,
and lower capacity prices and lower nuclear generation;
earned partially offset by
• favorable settlement of
economic hedges of $90 due to
settled prices relative to
hedged prices
ERCOT (245) (136.9) % • unfavorable purchased power 837 46.2 % • favorable purchased power of
of ($110) primarily due to $590 primarily due to lower
higher energy prices, higher energy prices relative to the
load, and absence of favorable prior year due to the February
recovery related to the 2021 extreme cold weather
February 2021 extreme cold event
weather event • favorable settlement of
• unfavorable settlement of economic hedges of $155 due to
economic hedges of ($105) due settled prices relative to
to settled prices relative to hedged prices
hedged prices • favorable fuel cost of $80
• unfavorable fuel cost of primarily due to lower gas
($30) primarily due to higher prices relative to the prior
gas prices relative to the year due to the February 2021
prior year extreme cold weather event
Other Power Regions (630) (60.1) % • unfavorable purchased power (1,314) (41.5) % • unfavorable purchased power
and net capacity impact of and net capacity impact of
($635) primarily due to higher ($1,775) primarily due to
energy prices and higher load higher energy prices, higher
• unfavorable fuel cost of load, lower generation and
($120) primarily due to higher lower cleared capacity volumes
gas prices; partially offset • unfavorable fuel cost of
by ($340) primarily due to higher
• unfavorable environmental gas prices
product optimization of ($60); • unfavorable environmental
partially offset by product optimization of ($80);
• favorable settlement of partially offset by
economic hedges of $200 due to • favorable settlement of
settled prices relative to economic hedges of $900 due to
hedged prices settled prices relative to
hedged prices
Other (448) (79.2) % • unfavorable net gas purchase (1,299) (56.8) % • unfavorable net gas purchase
costs and settlement of costs and settlement of
economic hedges of ($465) economic hedges of ($1,545)
• unfavorable energy purchases
of ($155) primarily due to
higher energy prices
• unfavorable fair value
adjustment related to gas
imbalances of ($100);
partially offset by
• favorable impact due to the
absence of LDC and pipeline
penalties due to the February
2021 extreme cold weather
event of $330
• favorable impact due to the
absence of accelerated nuclear
fuel amortization associated
with announced early plant
retirements of $150
Mark-to-market(b) (1,232) • gains on economic hedging (872) • gains on economic hedging
activities of $157 in 2022 activities of $1,328 in 2022
compared to gains of $1,389 in compared to gains of $2,200 in
2021 2021
Total $ (3,149) (203.7) % $ (3,651) (45.1) %
__________
(a)% Change in mark-to-market is not a meaningful measure.
(b)See Note 12 - Derivative Financial Instruments of the Combined Notes to
Consolidated Financial Statements for additional information on mark-to-market
gains and losses.
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For the three and nine months ended September 30, 2022 compared to 2021, changes
in Operating and maintenance expense consisted of the following:
Three Months Ended Nine Months Ended
September 30 September 30
(Decrease) Increase (Decrease) Increase
Labor, contracting, and materials(a) $ 153 $ 180
Plant retirements and divestitures(b) 94 88
Separation costs(c) 14 56
Credit loss expense(d) (1) (45)
COVID-19 direct costs (5) (24)
Nuclear refueling outage costs, including the co-owned Salem
generating units (17) 59
Asset impairments (45) (537)
Prior merger commitment(e) (50) (50)
Decommissioning-related activities(f) (99) 287
Other 7 39
Total (decrease) increase $ 51 $ 53
__________
(a)Primarily reflects increased employee-related costs, including labor,
stock-based compensation, and other incentives, etc.
(b)Reflects the absence of the reversal of charges recorded in the third quarter
of 2021 associated with the reversal of the previous decision to early retire
Byron and Dresden.
(c)Represents certain incremental costs related to the separation
(system-related costs, third-party costs paid to advisors, consultants, lawyers,
and other experts assisting in the separation), including a portion of the
amounts billed to us pursuant to the TSA.
(d)Primarily a result of the February 2021 extreme cold weather event.
(e)Reversal of a charge related to a prior merger commitment.
(f)Primarily reflects contractual offset of accelerated depreciation and
amortization associated with our previous decision to early retire the Byron and
Dresden nuclear facilities. See Note 10 - Asset Retirement Obligations of our
2021 Form 10-K for additional information.
Depreciation and amortization expense decreased for the three and nine months
ended September 30, 2022 compared to the same period in 2021, primarily due to
the accelerated depreciation and amortization associated with our previous
decision to early retire the Byron and Dresden nuclear facilities. This decision
was reversed on September 15, 2021 and depreciation for Byron and Dresden was
adjusted beginning September 15, 2021 to reflect the extended useful life
estimates. A portion of this accelerated depreciation and amortization is offset
in Operating and maintenance expense.
Taxes other than income taxes increased for the three and nine months ended
September 30, 2022 compared to the same period in 2021, primarily due to
increased gross receipt tax related to our retail operations. The offsetting
collection of gross receipts tax related to our retail operations is recorded in
Operating revenues.
(Loss) gain on sales of assets and businesses decreased for the three and nine
months ended September 30, 2022 compared to the same period in 2021, primarily
due to gains on sales of equity investments that became publicly traded entities
in the fourth quarter of 2020 and the first half of 2021 and a gain on sale of
our solar business in 2021.
Interest expense, net decreased for the three and nine months ended September
30, 2022 compared to the same period in 2021, primarily due to mark-to-market
gains related to our CR and West Medway II interest rate swaps and the
retirement of long-term debt in March 2022. See Note 17 - Debt and Credit
Agreements of our 2021 Form 10-K for additional information on the CR credit
facility and interest rate swaps.
Other, net decreased for the three and nine months ended September 30, 2022
compared to the same period in 2021, due to activity described in the table
below:
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Three Months Ended Nine Months Ended September
September 30, 30,
2022 2021 2022 2021
Net unrealized (losses) gains on NDT funds(a) $ (225) $ (94) $ (1,077) $ 33
Net realized (losses) gains on sale of NDT funds(a) (7)
101 45 349
Interest and dividend income on NDT funds(a) 22 26 70 73
Contractual elimination of income tax expense(b) (63) 11 (284) 150
Non-service net periodic benefit credit(c) 27 - 79 -
Net unrealized (losses) gains from CTV investments(d) (2) (179)
(27) (83)
Return to provision adjustment(e) 26 - (32) -
TSA billings(f) 12 - 32 -
Other 14 20 25 39
Total Other, net $ (196) $ (115) $ (1,169) $ 561
_________
(a)Unrealized gains, realized gains, and interest and dividend income on the NDT
funds are associated with the Non-Regulatory Agreement Units.
(b)Contractual elimination of income tax expense is associated with the income
taxes on the NDT funds of the Regulatory Agreement Units.
(c)Historically, we were allocated our portion of pension and OPEB non-service
credit (costs) from Exelon, which was included in Operating and maintenance
expense. Effective February 1, 2022, the non-service credit (cost) components
are included in Other, net, in accordance with single employer plan accounting.
See Note 11 - Retirement Benefits of the Combined Notes to Consolidated
Financial Statements for additional information.
(d)Net unrealized gains and losses from CTV investments that became publicly
traded entities in the fourth quarter of 2020 and the first half of 2021.
(e)This reflects amounts contractually owed to Exelon under the tax matters
agreement, which is offset in Income taxes. See Note 10 - Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information.
(f)Amounts we billed Exelon for services pursuant to the TSA. See Note 1 - Basis
of Presentation of the Combined Notes to Consolidated Financial Statements for
additional information.
Effective income tax rates were 39.4% and 21.7% for the three months ended
September 30, 2022 and 2021, respectively, and 73.1% and (1350.0)% for the nine
months ended September 30, 2022 and 2021, respectively. The effective tax rate
in 2022 is primarily due to the impacts of higher unrealized NDT losses on
Income before income taxes and one-time income tax adjustments. See Note 10 -
Income Taxes of the Combined Notes to Consolidated Financial Statements for
additional information.
Net income attributable to noncontrolling interests primarily relates to CRP for
the three and nine months ended September 30, 2022 and includes CENG and CRP for
the same period in 2021. The decrease for the three and nine months ended
September 30, 2022, compared to the same period in 2021, is primarily due to our
acquisition of EDF's interest in CENG on August 6, 2021. See Note 2 - Mergers,
Acquisitions, and Dispositions of our 2021 Form 10-K for additional information.
Significant 2022 Transactions and Developments
Separation from Exelon
On February 21, 2021, Exelon's Board of Directors approved a plan to separate
its competitive generation and customer-facing energy businesses into a
stand-alone publicly traded company (the "separation"). Exelon completed the
separation on February 1, 2022. We incurred separation costs of $30 million and
$99 million for the three and nine months ended September 30, 2022,
respectively, which are primarily recorded in Operating and maintenance expense.
Separation costs for the three and nine months ended September 30, 2021 were not
material. 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. These costs have been excluded from Adjusted EBITDA
(non-GAAP). See Note 1 - Basis of Presentation of the Combined Notes to
Consolidated Financial Statements for additional information.
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Other Key Business Drivers
Power Markets
Russia and Ukraine Conflict
We are closely monitoring developments of the Russia and Ukraine conflict
including United States sanctions against Russian energy exports, the potential
for sanctions on Russian nuclear fuel supply, and enrichment activities, as well
as yet undefined action by Russia to limit energy deliveries. To-date, our
nuclear fuel deliveries have not been affected by the Russia and Ukraine
conflict. Our nuclear fuel is obtained predominantly through long-term uranium
supply and service contracts. We work with a diverse set of domestic and
international suppliers years in advance to procure our nuclear fuel, and
therefore, we have enough nuclear fuel to support all our refueling needs for
multiple years regardless of sanctions. We are taking affirmative action by
working with our diverse set of suppliers to ensure we can secure the nuclear
fuel needed to continue to operate our nuclear fleet long-term. We are also
working with Federal policymakers and other stakeholders to facilitate the
expansion of the domestic nuclear fuel cycle within the United States to improve
carbon-free energy security.
Hedging Strategy
We are exposed to commodity price risk associated with the unhedged portion of
our electricity portfolio. We enter into non-derivative and derivative
contracts, including options, swaps, and forward and futures contracts, all with
credit-approved counterparties, to hedge this anticipated exposure. For merchant
revenues not already hedged via comprehensive state programs, such as the CMC in
Illinois, we utilize a three-year ratable sales plan to align our hedging
strategy with our financial objectives. The prompt three-year merchant revenues
are hedged on an approximate rolling 90%/60%/30% basis. We may also enter into
transactions that are outside of this ratable hedging program. As of
September 30, 2022, the percentage of expected generation hedged for the
Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 97%-100% and
92%-95% for 2022 and 2023, respectively. We have been and will continue to be
proactive in using hedging strategies to mitigate commodity price risk.
We procure natural gas through long-term and short-term contracts and
spot-market purchases. Nuclear fuel assemblies are obtained predominantly
through long-term uranium concentrate supply contracts, contracted conversion
services, contracted enrichment services, or a combination thereof, and
contracted fuel fabrication services. The supply markets for uranium
concentrates and certain nuclear fuel services are subject to price fluctuations
and availability restrictions. Approximately 55% of our uranium concentrate
requirements from 2022 through 2026 are supplied by three suppliers. In the
event of non-performance by these or other suppliers, we believe that
replacement uranium concentrate can be obtained, although at prices that may be
unfavorable when compared to the prices under the current supply agreements.
Geopolitical developments have the potential to impact delivery from multiple
suppliers in the international uranium processing industry. Non-performance by
these counterparties could have a material adverse impact on our consolidated
financial statements.
See Note 12 - Derivative Financial Instruments of the Combined Notes to
Consolidated Financial Statements and ITEM 3. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK for additional information.
Other Environmental Regulation
Federal Climate Change Legislation and Regulation. On August 16, 2022, Congress
passed and President Biden signed into law the Inflation Reduction Act of 2022,
which, among other things, includes federal tax credits, certain of which are
transferable or fully refundable, for clean energy technologies including
existing nuclear plants and hydrogen production facilities. The Nuclear PTC
recognizes the contributions of carbon-free nuclear power by providing a federal
tax credit of up to $15/MWh, subject to phase-out, beginning in 2024 and
continuing through 2032. The Hydrogen PTC provides a 10-year federal tax credit
of up to $3/kilogram for clean hydrogen produced after 2022 from facilities that
begin construction prior to 2033. Both the Nuclear and Hydrogen PTCs include
adjustments for inflation. The Hydrogen PTC creates additional opportunities for
our nuclear fleet to enable decarbonization of other industries through the
production of clean hydrogen. With this policy support, we expect that many of
our nuclear assets will operate through the end of the Nuclear PTC period.
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Regulation of GHGs from Power Plants under the Clean Air Act. The EPA's 2015
Clean Power Plan (CPP) established regulations addressing carbon dioxide
emissions from existing fossil-fired power plants under Clean Air Act Section
111(d). The CPP's carbon pollution limits could be met through shifting
generation from higher-emitting units to lower- or zero-emitting units. In July
2019, the EPA published the Affordable Clean Energy rule, which repealed the CPP
and replaced it with less stringent emissions guidelines based on heat rate
improvement measures. We, as part of Exelon, together with a coalition of other
electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C.
Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as
unlawful. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit
vacated the Affordable Clean Energy Rule. On October 29, 2021, the Supreme Court
granted certiorari to examine the extent of EPA's authority to regulate GHGs
from power plants. The electric utilities coalition filed a brief and
participated in oral argument before the Supreme Court. On June 30, 2022, the
Supreme Court issued a decision holding that EPA did not have the authority to
require "generation shifting" from coal to natural gas and renewables to reduce
sector-wide emissions, as it had done in CPP. The EPA has indicated it will
promulgate new GHG limits for existing power plants in March 2023.
State Climate Change Legislation and Regulation. On July 1, 2022, Pennsylvania
formally began participation in the RGGI, joining Connecticut, Delaware, Maine,
Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island,
Vermont, and Virginia. The program requires most fossil fuel-fired power plants
in the region to hold allowances, sold at auction or on the secondary market,
for each ton of CO2 emissions. Non-emitting resources do not have to purchase or
hold these allowances. The process of bringing Pennsylvania into the RGGI began
in October 2019 when the Governor of Pennsylvania signed an Executive Order
directing the PA DEP to commence the rulemaking to join the RGGI and that rule
went into effect with Pennsylvania joining RGGI on July 1, 2022. However, on
July 8, 2022, the Commonwealth Court of Pennsylvania entered two preliminary
injunctions preventing Pennsylvania from participating in RGGI while ongoing
legal challenges proceed. At least one of those injunctions currently remains in
place while it is appealed to the Pennsylvania Supreme Court, where briefing of
the appeal will be completed by December 4, 2022. In addition, the Commonwealth
Court of Pennsylvania is scheduled to hear oral arguments in November 2022 on
the merits of the challenges to Pennsylvania entering RGGI. On September 26, the
Virginia State Air Pollution Control Board published a Notice of Intended
Regulatory Action to begin the process for repealing "Regulation for Emissions
Trading," which implemented Virginia's participation in RGGI. The Virginia
Department of Environmental Quality was directed to reevaluate Virginia's
participation in RGGI and begin a regulatory process to end it per a governor's
order.
Mercury and Air Toxics Standards (MATS). In 2011, the EPA signed a final rule,
known as MATS, to reduce emissions of hazardous air pollutants from coal- and
oil-fired power plants. MATS requires coal-fired power plants to achieve high
removal rates of mercury, acid gases, and other metals, and to make capital
investments in pollution control equipment and incur higher operating expenses.
This rule has been subject to various challenges since issuance, see PART I,
ITEM 1. BUSINESS of our 2021 Form 10-K for additional information on the
procedural history of this matter. On January 20, 2021, President Biden issued
an Executive Order directing the EPA to reconsider its May 22, 2020, revised
supplemental finding, and the EPA subsequently moved for the U.S. Court of
Appeals for the D.C. Circuit to place the cases challenging that finding in
abeyance pending its reconsideration, which the court did on February 21, 2021.
On February 9, 2022 EPA published a proposal to revoke the 2020 revised
supplemental finding and reaffirm that it is "appropriate and necessary" to
regulate hazardous air pollutant emissions from coal- and oil-fired power
plants. Additionally, in February 2022, the U.S. Court of Appeals for the D.C.
Circuit granted unopposed motions to substitute Constellation in place of Exelon
in these cases. Comments on the proposed regulation were due April 11, 2022. If
EPA promulgates a final rule revoking the 2020 revised supplemental finding
determination, then the cases currently before the U.S. Court of Appeals for the
D.C. Circuit concerning MATS may be dismissed as moot or placed in abeyance
pending the disposition of any petitions for review that may be filed
challenging that final rule. We cannot reasonably predict the outcome of this
matter.
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Critical Accounting Policies and Estimates
Management makes a number of significant estimates, assumptions, and judgements
in the preparation of our financial statements. The following policy was added
as a result of separation. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Critical Accounting Policies and
Estimates in our 2021 Form 10-K for further information.
Retirement Benefits
Defined Benefit Pension and Other Postretirement Employee Benefits
We sponsor defined benefit pension and OPEB plans for most current employees.
The measurement of the plan obligations and costs of providing benefits involves
various factors, including the development of valuation assumptions and inputs
and accounting policy elections. When developing the required assumptions, we
consider historical information as well as future expectations. The measurement
of projected benefit obligations and costs is affected by several assumptions
including the discount rate, the long-term expected rate of return on plan
assets, the anticipated rate of increase of health care costs, our
contributions, the rate of compensation increases, and the long-term expected
investment rate credited to employees of certain plans, among others. The
assumptions are updated annually and upon any interim remeasurement of the plan
obligations.
Pension and OPEB plan assets include equity securities, including U.S. and
international securities, and fixed income securities, as well as certain
alternative investment classes such as real estate, private equity, and hedge
funds.
Expected Rate of Return on Plan Assets. In determining the EROA, we consider
historical economic indicators (including inflation and GDP growth) that impact
asset returns, as well as expectation regarding future long-term capital market
performance, weighted by our target asset class allocations. We calculate the
amount of expected return on pension and OPEB plan assets by multiplying the
EROA by the MRV of plan assets at the beginning of the year, taking into
consideration anticipated contributions and benefit payments to be made during
the year. In determining MRV, the authoritative guidance for pensions and
postretirement benefits allows the use of either fair value or a calculated
value that recognizes changes in fair value in a systematic and rational manner
over not more than five years. For the majority of pension plan assets, we use a
calculated value that adjusts for 20% of the difference between fair value and
expected MRV of plan assets. Use of this calculated value approach enables less
volatile expected asset returns to be recognized as a component of pension cost
from year to year. For OPEB plan assets and certain pension plan assets, we use
fair value to calculate the MRV.
Discount Rate. The discount rates are determined by developing a spot rate curve
based on the yield to maturity of a universe of high-quality non-callable (or
callable with make whole provisions) bonds with similar maturities to the
related pension and OPEB obligations. The spot rates are used to discount the
estimated future benefit distribution amounts under the pension and OPEB plans.
The discount rate is the single level rate that produces the same result as the
spot rate curve. We utilize an analytical tool developed by our actuaries to
determine the discount rates.
Mortality. The mortality assumption is composed of a base table that represents
the current expectation of life expectancy of the population adjusted by an
improvement scale that attempts to anticipate future improvements in life
expectancy. In 2022, we adopted the revised mortality tables and projection
scales released by the SOA.
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Sensitivity to Changes in Key Assumptions. The following table illustrates the
effects of changing certain of the actuarial assumptions reflected above on the
remeasurement completed at separation as discussed in Note 11 - Retirement
Benefits of the Combined Notes to Consolidated Financial Statements, while
holding all other assumptions constant:
Actual Assumption
Increase / (Decrease)
Actuarial Assumption Pension OPEB Assumption Pension OPEB Total
Change in 2022 cost:
Discount rate(a) 3.23 % 3.21 % 0.5 % $ (22) $ (1) $ (23)
3.23 % 3.21 % (0.5) % 28 7 35
EROA 7.00 % 6.50 % 0.5 % (41) (4) (45)
7.00 % 6.50 % (0.5) % 41 4 45
Change in benefit obligation:
Discount rate(a) 3.23 % 3.21 % 0.5 % (536) (99) (635)
3.23 % 3.21 % (0.5) % 620 115 735
__________
(a)In general, the discount rate will have a larger impact on the pension and
OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount
rate sensitivities above cannot necessarily be extrapolated for larger increases
or decreases in the discount rate. Additionally, we utilize a liability-driven
hedging investment strategy for our pension asset portfolio. The sensitivities
shown above do not reflect the offsetting impact that changes in discount rates
may have on pension asset returns.
See Note 1 - Basis of Presentation and Note 11 - Retirement Benefits of the
Combined Notes to Consolidated Financial Statements for additional information
regarding the accounting for the defined benefit pension and OPEB plans.
Liquidity and Capital Resources
All results included throughout the liquidity and capital resources section are
presented on a GAAP basis.
Our operating and capital expenditures requirements are provided by internally
generated cash flows from operations, the sale of certain receivables, as well
as funds from external sources in the capital markets and through bank
borrowings. Our business is capital intensive and requires considerable capital
resources. We annually evaluate our financing plan and credit line sizing,
focusing on maintaining our investment grade ratings while meeting our cash
needs to fund capital requirements, including construction expenditures, retire
debt, pay dividends, fund pension and OPEB obligations, and invest in new and
existing ventures. A broad spectrum of financing alternatives beyond the core
financing options can be used to meet our needs and fund growth, including
monetizing assets in the portfolio via project financing, asset sales, and the
use of other financing structures (e.g., joint ventures, minority partners,
etc.). Our access to external financing on reasonable terms depends on our
credit ratings and current overall capital market business conditions. If these
conditions deteriorate to the extent that we no longer have access to the
capital markets at reasonable terms, we have access to various facilities with
aggregate bank commitments of $5.8 billion. We utilize these facilities to
support our commercial paper programs, provide for other short-term borrowings
and to issue letters of credit. See the "Credit Matters" section below for
additional information. We expect cash flows to be sufficient to meet operating
expenses, financing costs, and capital expenditure requirements. See Note 13 -
Debt and Credit Agreements of the Combined Notes to Consolidated Financial
Statements for additional information on our debt and credit agreements.
Pursuant to the Separation Agreement between us and Exelon, we received a cash
payment of $1.75 billion from Exelon on January 31, 2022. See Note 1 - Basis of
Presentation of the Combined Notes to Consolidated Financial Statements for
additional information on the separation.
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NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities
demonstrate reasonable assurance that sufficient funds will be available in
certain minimum amounts to decommission the facility. These NRC minimum funding
levels are typically based upon the assumption that decommissioning activities
will commence after the end of the current licensed life of each unit. If a unit
fails the NRC minimum funding test, then the plant's owners or parent companies
would be required to take steps, such as providing financial guarantees through
surety bonds, letters of credit, or parent company guarantees or making
additional cash contributions to the NDT fund to ensure sufficient funds are
available. See Note 8 - Nuclear Decommissioning of the Combined Notes to
Consolidated Financial Statements for additional information.
If a nuclear plant were to retire before the end of its licensed life, there is
a risk that it will no longer meet the NRC minimum funding requirements due to
the earlier commencement of decommissioning activities and a shorter time period
over which the NDT funds could appreciate in value. A shortfall could require
that we address the shortfall by providing additional financial assurances, such
as surety bonds, letters of credit, or parent company guarantees for our share
of the funding assurance. However, the amount of any assurance will ultimately
depend on the decommissioning approach, the associated level of costs, and the
NDT fund investment performance going forward. No later than two years after
shutting down a plant, we must submit a PSDAR to the NRC that includes the
planned option for decommissioning the site.
Upon issuance of any additional financial assurance mechanisms to address a
decommissioning funding shortfall, subject to satisfying various regulatory
preconditions, each site would be able to utilize the respective NDT funds for
radiological decommissioning costs, which represent the majority of the total
expected decommissioning costs. However, under the regulations, the NRC must
approve an exemption in order for us to utilize the NDT funds to pay for
non-radiological decommissioning costs (i.e. spent fuel management and site
restoration costs, if applicable). Any amounts not covered by an exemption would
be borne by us without reimbursement.
As of September 30, 2022, we are not required to provide any additional
financial assurance for TMI Unit 1 under the SAFSTOR scenario that is the
planned decommissioning option, as described in the TMI Unit 1 PSDAR filed with
the NRC on April 5, 2019. On October 16, 2019, the NRC granted our exemption
request to use the TMI Unit 1 NDT funds for spent fuel management costs. An
additional exemption request to allow the TMI Unit 1 NDT funds to be used for
site restoration costs was submitted to the NRC on May 20, 2021. On June 8,
2022, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for
site restoration costs.
Cash Flows from Operating Activities
Our cash flows from operating activities primarily result from the sale of
electric energy and energy-related products and services to customers. Our
future cash flows from operating activities may be affected by future demand
for, and market prices of, energy and our ability to continue to produce and
supply power at competitive costs, as well as to obtain collections from
customers and the sale of certain receivables.
See Note 3 - Regulatory Matters and Note 15 - 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 nine months ended September 30, 2022 and 2021:
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