CONSTELLATION ENERGY CORPORATION (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 for the three and six months endedJune 30, 2022 compared to the same period in 2021. For additional information regarding the financial results for the three and six months endedJune 30, 2022 and 2021 see the discussions of Results of Operations below. Three Months Ended June 30, Favorable Six Months Ended June 30, Favorable (Unfavorable) (Unfavorable) 2022 2021 Variance 2022 2021 Variance GAAP Net loss$ (111) $ (61) $ (50)$ (5) $ (854) $ 849 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. The following table provides a reconciliation between Net loss attributable to common shareholders as determined in accordance with GAAP and Adjusted EBITDA (non-GAAP) for the three and six months endedJune 30, 2022 compared to the same period in 2021. 66
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Six Months Ended
Three Months Ended June 30, June 30,
2022 2021 2022 2021
Net Loss Attributable to Common Shareholders $ (111) $ (61) $ (5) $ (854)
Income Taxes(a) (270) 110 (323) (70)
Depreciation and Amortization(b) 277 930 557 1,869
Interest Expense, Net 56 76 112 148
Unrealized (Gain)/Loss on Fair Value Adjustments(c) (24) (447) 94 (577)
Asset Impairments(d) - 492 - 492
Plant Retirements and Divestitures(e) (8) 49 (8) 47
Decommissioning-Related Activities(f) 684 (513) 1,038 (884)
Pension & OPEB Non-Service Credits (33) (14) (58) (25)
Separation Costs(g) 31 6 68 9
COVID-19 Direct Costs(h) - 7 - 19
Acquisition-Related Costs(i) - 2 - 10
ERP System Implementation Costs(j) 5 3 11 5
Change in Environmental Liabilities 8 - 8 3
Cost Management Program - 3 - 5
Noncontrolling Interests(k) (12) 13 (25) (6)
Adjusted EBITDA (non-GAAP) $ 603 $ 656 $ 1,469 $ 191 __________
(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 in theNew 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. (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 costs related to the separation including system-related costs, third-party costs paid to advisors, consultants, lawyers, other experts assisting in the separation. (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)Reflects elimination from results for the noncontrolling interests related to certain adjustments, primarily relating to CRP in 2022 and CENG in 2021. 67
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Results of Operations
Three Months Ended June 30, Favorable Six Months Ended June 30, Favorable
(Unfavorable) (Unfavorable)
2022 2021 Variance 2022 2021 Variance
Operating revenues $ 5,465 $ 4,153 $ 1,312 $ 11,056 $ 9,712 $ 1,344
Operating expenses
Purchased power and fuel 3,508 1,947 (1,561) 7,059 6,557 (502)
Operating and maintenance 1,273 1,474 201 2,477 2,476 (1)
Depreciation and amortization 277 930 653 557 1,869 1,312
Taxes other than income taxes 133 118 (15) 268 239 (29) Total operating expenses 5,191 4,469 (722) 10,361 11,141 780 (Loss) gain on sales of assets and businesses (2) 8 (10) 13 79 (92) Operating income (loss) 272 (308) 580 708 (1,350) 2,058 Other income and (deductions) Interest expense, net (56) (76) 20 (112) (148) 36 Other, net (654) 508 (1,162) (973) 675 (1,648) Total other income and (deductions) (710) 432 (1,142) (1,085) 527
(1,612)
(Loss) income before income taxes (438) 124 (562) (377) (823) 446 Income taxes (328) 110 438 (381) (70) (311) Equity in losses of unconsolidated affiliates (3) (1) (2) (6) (3) (3) Net (loss) income (113) 13 (126) (2) (756) 754 Net (loss) income attributable to noncontrolling interests (2) 74 (76) 3 98
(95)
Net loss attributable to common shareholders$ (111) $ (61) $ (50) $ (5)$ (854) 849 Three Months EndedJune 30, 2022 Compared to Three Months EndedJune 30, 2021 . Net loss attributable to common shareholders increased by$50 million primarily due to:
•Higher net realized and unrealized NDT losses;
•Lower net mark-to-market gains;
•Higher net unrealized and realized gains on equity investments;
•The absence of a prior year gain on the sale of our solar business;
•Decreased capacity revenues; and
•Unfavorable impacts from nuclear outages.
The increases 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 onSeptember 15, 2021 ; and our decision in the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024 ;
•The absence of impairments of the
•Higher realized energy prices; and
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•Lower nuclear fuel costs due to the absence of accelerated amortization of nuclear fuel and lower prices.
Six months endedJune 30, 2022 Compared to Six months endedJune 30, 2021 . Net loss attributable to common shareholders decreased by$849 million primarily due to:
•The absence of impacts from the
•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 onSeptember 15, 2021 , and our decision in the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024;
•The absence of impairments of the
•Higher realized energy prices; and
•Lower nuclear fuel costs due to the absence of accelerated amortization of nuclear fuel and lower prices.
The increases were partially offset by:
•Higher net realized and unrealized NDT losses;
•Higher net mark-to-market losses;
•Decreased capacity revenues;
•Higher net unrealized and realized gains on equity investments;
•Unfavorable impacts from nuclear outages;
•Absence of a prior year gain on the sale of our solar business;
•Increased tax expense due to one-time items related to the separation;
•Increased separation costs; and
•Higher contracting and labor costs.
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 , andOther Power Regions. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments. 69
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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 six months ended
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 Variance % Change(a) 2022 2021 Variance % Change(a)
Mid-Atlantic $ 1,202 $ 1,091 $ 111 10.2 % $ 2,307 $ 2,255 $ 52 2.3 %
Midwest 1,101 962 139 14.4 % 2,298 1,960 338 17.2 %
New York 390 381 9 2.4 % 755 719 36 5.0 %
ERCOT 485 275 210 76.4 % 720 532 188 35.3 %
Other Power Regions 1,327 1,038 289 27.8 % 3,254 2,469 785 31.8 %
Total electric revenues 4,505 3,747 758 20.2 % 9,334 7,935 1,399 17.6 %
Other 1,259 645 614 95.2 % 2,941 2,100 841 40.0 %
Mark-to-market losses (299) (239) (60) (1,219) (323) (896)
Total Operating revenues $ 5,465 $ 4,153 $ 1,312 31.6 % $ 11,056 $ 9,712 $ 1,344 13.8 %
__________(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 June 30, Six Months Ended June 30,
Supply Source (GWhs) 2022 2021 Variance % Change 2022 2021 Variance % Change
Nuclear Generation(a)
Mid-Atlantic 12,609 13,197 (588) (4.5) % 25,732 26,451 (719) (2.7) %
Midwest 23,342 23,299 43 0.2 % 46,804 46,454 350 0.8 %
New York (b) 6,571 6,576 (5) (0.1) % 12,584 13,133 (549) (4.2) %
Total Nuclear Generation 42,522 43,072 (550) (1.3) % 85,120 86,038 (918) (1.1) %
Natural Gas, Oil, and
Renewables
Mid-Atlantic 616 522 94 18.0 % 1,343 1,185 158 13.3 %
Midwest 281 262 19 7.3 % 649 585 64 10.9 %
New York - - - - % - 1 (1) (100.0) %
ERCOT 2,913 2,797 116 4.1 % 5,887 5,581 306 5.5 %
Other Power Regions 1,874 2,239 (365) (16.3) % 4,777 5,205 (428) (8.2) %
Total Natural Gas , Oil, and
Renewables 5,684 5,820 (136) (2.3) % 12,656 12,557 99 0.8 %
Purchased Power
Mid-Atlantic 2,898 3,089 (191) (6.2) % 5,656 7,571 (1,915) (25.3) %
Midwest 156 131 25 19.1 % 351 310 41 13.2 %
ERCOT 1,413 1,259 154 12.2 % 2,149 2,031 118 5.8 %
Other Power Regions 12,436 12,356 80 0.6 % 26,096 25,189 907 3.6 %
Total Purchased Power 16,903 16,835 68 0.4 % 34,252 35,101 (849) (2.4) %
Total Supply/Sales by Region
Mid-Atlantic 16,123 16,808 (685) (4.1) % 32,731 35,207 (2,476) (7.0) %
Midwest 23,779 23,692 87 0.4 % 47,804 47,349 455 1.0 %
New York (b) 6,571 6,576 (5) (0.1) % 12,584 13,134 (550) (4.2) %
ERCOT 4,326 4,056 270 6.7 % 8,036 7,612 424 5.6 %
Other Power Regions 14,310 14,595 (285) (2.0) % 30,873 30,394 479 1.6 %
Total Supply/Sales by Region 65,109 65,727 (618) (0.9) % 132,028 133,696 (1,668) (1.2) %
__________
(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 Six Months Ended
June 30, June 30,
2022 2021 2022 2021
Nuclear fleet capacity factor(a) 94.2 % 93.8 % 93.6 % 94.0 %
Refueling outage days 66 66 142 150
Non-refueling outage days 15 7 25 10
__________
(a)Prior year capacity factor was previously reported as 93.7% and 94.5% for the
three and six months ended June 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 participate in state-sponsored programs that recognize the
carbon-free attributes of our nuclear generation. ZEC prices have a significant
impact on operating revenues. The following table presents the ZEC prices
($/MWh) for each of our major regions in which state programs have been enacted.
Prices reflect the weighted average price for the various delivery periods
within each calendar year.
Three Months Ended June 30, Six Months Ended June 30,
State (Region)(a) 2022 2021 Variance % Change 2022 2021 Variance % Change- - %$ 10.00 $ 10.00 $ - - % Illinois (Midwest) 15.00 16.50 (1.50) (9.1) % 15.75 16.50 (0.75) (4.5) % New York (New York) 21.38 21.38 - - % 21.38 20.49 0.89 4.3 % __________ (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. 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 ($30.30 per MWh for initial delivery periodJune 1, 2022 throughMay 31, 2023 ). If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. For the month ofJune 2022 , the CMC price per MWh was a net negative value$(52.30) . 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, exceptERCOT which does not have a capacity market. We also incur capacity costs associated with load served, except inERCOT . Capacity prices have a significant impact on our operating revenues and purchased power and fuel. The following table presents the average capacity prices ($/MW Day) for each of our major regions. Prices reflect the weighted average price for the various auction periods within each calendar year. Three Months Ended June 30, Six Months Ended June 30, Location (Region) 2022 2021 Variance % Change 2022 2021 Variance % Change Eastern Mid-Atlantic Area Council (Mid-Atlantic)$ 143.11 $ 180.49 $ (37.38) (20.7) %$ 154.42 $ 184.18 $ (29.76) (16.2) % ComEd (Midwest) 153.35 190.60 (37.25) (19.5) % 174.45 189.36 (14.91) (7.9) % Rest of State (New York) 75.67 118.00 (42.33) (35.9) % 80.39 65.51 14.88 22.7 % SoutheastNew England (Other) 145.13 169.23 (24.10) (14.2) % 149.75 172.95 (23.20) (13.4) % 72
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Electricity Prices. The price of electricity has a significant impact on our
operating revenues and purchased power cost. The following table presents the
average day-ahead around-the-clock price ($/MWh) for each of our major regions.
Three Months Ended June 30, Six Months Ended June 30,
Location (Region) 2022 2021 Variance % Change 2022 2021 Variance % Change
PJM West (Mid-Atlantic) $ 77.17 $ 28.56 $ 48.61 170.2 % $ 66.28 $ 29.77 $ 36.51 122.6 %
ComEd (Midwest) 66.46 26.95 39.51 146.6 % 53.36 27.96 25.40 90.8 %
Central (New York) 41.75 18.06 23.69 131.2 % 53.85 21.87 31.98 146.2 %
North (ERCOT) 70.79 32.04 38.75 120.9 % 53.92 270.66 (216.74) (80.1) %
Southeast Massachusetts
(Other)(a) 69.15 29.43 39.72 135.0 % 90.38 40.04 50.34 125.7 %
__________(a)Reflects New England, which comprises the majority of the activity in the Other region.
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For the three and six months ended
Variance % Change(a) Three Months Ended June 30 Variance % Change(a) Six Months Ended June 30
Mid-Atlantic $ 111 10.2 % • favorable retail load $ 52 2.3 % • favorable retail load
revenue of $140 primarily due revenue of $240 primarily due
to higher energy prices; to higher energy prices;
partially offset by partially offset by
• unfavorable settled • unfavorable wholesale load
economic hedges of ($10 ) due revenue of ($115 ) primarily
to settled prices relative to due to lower volumes
hedged prices partially offset by higher
energy prices
• unfavorable settled
economic hedges of ($60 ) due
to settled prices relative to
hedged prices
Midwest 139 14.4 % • favorable net wholesale 338 17.2 % • favorable net wholesale
load and generation revenue load and generation revenue
of $275 primarily due to of $495 primarily due to
higher energy prices and higher energy prices and
higher volumes, partially higher volumes, partially
offset by CMC program offset by CMC program
activity and lower cleared activity and lower cleared
capacity volumes capacity volumes
• favorable retail load • favorable retail load
revenue of $80 primarily due revenue of $100 primarily due
to higher energy prices; to higher energy prices;
partially offset by partially offset by
• unfavorable settled • unfavorable settled
economic hedges of ($210 ) due economic hedges of ($250 ) due
to settled prices relative to to settled prices relative to
hedged prices hedged prices
New York 9 2.4 % • favorable retail load 36 5.0 % • favorable retail load
revenue of $65 primarily due revenue of $140 primarily due
to higher energy prices and to higher energy prices and
higher volumes higher volumes
• favorable generation • favorable generation
revenue of $40 primarily due revenue of $95 primarily due
to higher energy prices; to higher energy prices;
partially offset by partially offset by
• unfavorable settled • unfavorable settled
economic hedges of ($90 ) due economic hedges of ($200 ) due
to settled prices relative to to settled prices relative to
hedged prices hedged prices
ERCOT 210 76.4 % • favorable settled economic 188 35.3 % • favorable settled economic
hedges of $140 due to settled hedges of $305 due to settled
prices relative to hedged prices relative to hedged
prices prices; partially offset by
• favorable retail load • unfavorable wholesale load
revenue of $65 primarily due revenue of ($60 ) and retail
to higher energy prices and load revenue of ($40 )
higher volumes primarily due to lower energy
prices relative to the prior
year due to the February 2021
extreme cold weather event
Other Power Regions 289 27.8 % • favorable settled economic 785 31.8 % • favorable settled economic
hedges of $155 due to settled hedges of $350 due to settled
prices relative to hedged prices relative to hedged
prices prices
• favorable retail load • favorable wholesale load
revenue of $60 primarily due revenue of $245 primarily due
to higher energy prices to higher energy prices and
• favorable wholesale load higher volumes
revenue of $50 primarily due • favorable retail load
to higher energy prices and revenue of $160 primarily due
higher volumes to higher energy prices and
higher volumes
Other 614 95.2 % • favorable gas revenue of 841 40.0 % • favorable gas revenue of
$525 primarily due to higher $865 primarily due to higher
gas prices gas prices
• favorable energy revenue of • favorable energy revenue of
$115 primarily due to higher $225 primarily due to higher
energy prices 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) (60) • losses on economic hedging (896) • losses on economic hedging
activities of ($299 ) in 2022 activities of ($1,219 ) in
compared to losses of ($239 ) 2022 compared to losses of
in 2021 ($323 ) in 2021
Total $ 1,312 31.6 % $ 1,344 34.6 %
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-------------------------------------------------------------------------------- Table of Contents __________ (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.
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 six months ended
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 Variance % Change(a) 2022 2021 Variance % Change(a)
Mid-Atlantic $ 657 $ 519 $ (138) (26.6) % $ 1,252 $ 1,114 $ (138) (12.4) %
Midwest 449 304 (145) (47.7) % 861 600 (261) (43.5) %
New York 97 89 (8) (9.0) % 195 183 (12) (6.6) %
ERCOT 396 192 (204) (106.3) % 551 1,634 1,083 66.3 %
Other Power Regions 1,158 902 (256) (28.4) % 2,799 2,116 (683) (32.3) %
Total electric purchased
power and fuel 2,757 2,006 (751) (37.4) % 5,658 5,647 (11) (0.2) %
Other 1,094 494 (600) (121.5) % 2,573 1,722 (851) (49.4) %
Mark-to-market gains (343) (553) (210) (1,172) (812) 360
Total purchased power and
fuel $ 3,508 $ 1,947 $ (1,561) (80.2) % $ 7,059 $ 6,557 $ (502) (7.7) %
__________(a)% Change in mark-to-market is not a meaningful measure.
For the three and six months ended
Variance % Change(a) Three Months Ended June 30 Variance % Change(a) Six Months Ended June 30
Mid-Atlantic $ (138) (26.6) % • unfavorable purchased power $ (138) (12.4) % • unfavorable purchased power
and net capacity impact of and net capacity impact of
($165 ) primarily due to ($165 ) primarily due to
higher energy prices, lower higher energy prices, lower
nuclear generation and lower nuclear generation, lower
capacity prices earned; capacity prices earned, and
partially offset by lower cleared capacity
• favorable settlement of volumes; partially offset by
economic hedges of $40 due to • favorable settlement of
settled prices relative to economic hedges of $35 due to
hedged prices settled prices relative to
hedged prices
Midwest (145) (47.7) % • unfavorable purchased power (261) (43.5) % • unfavorable purchased power
and net capacity impact of and net capacity impact of
($180 ) primarily due to ($320 ) primarily due to
higher energy prices and higher energy prices, higher
lower capacity prices earned; load, and lower capacity
partially offset by prices earned; partially
• favorable nuclear fuel cost offset by
of $30 primarily due to • favorable nuclear fuel cost
accelerated amortization of of $65 primarily due to
nuclear fuel in prior periods accelerated amortization of
nuclear fuel in prior periods
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New York (8) (9.0) % • favorable settlement of (12) (6.6) % • unfavorable purchased power
economic hedges of $70 due to and net capacity impact of
settled prices relative to ($100 ) primarily due to
hedged prices; partially higher energy prices, higher
offset by load, and lower nuclear
• unfavorable purchased power generation; partially offset
and net capacity impact of by
($70 ) primarily due to higher • favorable settlement of
energy prices, higher load, economic hedges of $95 due to
and lower capacity prices settled prices relative to
earned hedged prices
ERCOT (204) (106.3) % • unfavorable purchased power 1,083 66.3 % • favorable purchased power
of ($130 ) primarily due to of $695 primarily due to
higher energy prices and lower energy prices relative
higher load to the prior year due to the
• unfavorable settlement of February 2021 extreme cold
economic hedges of ($55 ) due weather event
to settled prices relative to • favorable settlement of
hedged prices economic hedges of $260 due
to settled prices relative to
hedged prices
• favorable fuel cost of $115
primarily due to lower gas
prices relative to the prior
year due to the February 2021
extreme cold weather event
Other Power Regions (256) (28.4) % • unfavorable purchased power (683) (32.3) % • unfavorable purchased power
and net capacity impact of and net capacity impact of
($455 ) primarily due to ($1,140 ) primarily due to
higher energy prices and higher energy prices, higher
higher load; partially offset load, lower generation and
by lower cleared capacity
• favorable settlement of volumes
economic hedges of $165 due • unfavorable fuel cost of
to settled prices relative to ($215 ) primarily due to
hedged prices higher gas prices; partially
offset by
• favorable settlement of
economic hedges of $705 due
to settled prices relative to
hedged prices
Other (600) (121.5) % • unfavorable net gas (851) (49.4) % • unfavorable net gas
purchase costs and settlement purchase costs and settlement
of economic hedges of ($530 ) of economic hedges of
• unfavorable energy ($1,085 )
purchases of ($120 ) primarily • unfavorable energy
due to higher energy prices; purchases of ($205 ) primarily
partially offset by due to higher energy prices;
• favorable impact due to the partially offset by
absence of accelerated • favorable impact due to the
nuclear fuel amortization absence of LDC and pipeline
associated with announced penalties due to the February
early plant retirements of 2021 extreme cold weather
$50 event of $330
• favorable impact due to the
absence of accelerated
nuclear fuel amortization
associated with announced
early plant retirements of
$105
Mark-to-market(b) (210) • gains on economic hedging 360 • gains on economic hedging
activities of $343 in 2022 activities of $1,172 in 2022
compared to gains of $553 in compared to gains of $812 in
2021 2021
Total $ (1,561) (80.2) % $ (502) (7.7) %
__________(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 six months ended
Three Months Ended Six Months Ended
June 30 June 30
(Decrease) Increase (Decrease) Increase
Asset impairments $ (492) $ (492)
COVID-19 direct costs (7) (19)
Credit loss expense(a) (3) (44)
Separation costs 25 42
Labor, other benefits, contracting, and materials 40 26
Nuclear refueling outage costs, including the co-owned
47 76
Decommissioning-related activities(b) 164 387
Other 25 25
Total (decrease) increase $ (201) $ 1
__________
(a)Primarily a result of the February 2021 extreme cold weather event
(b)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 six months
ended June 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, and our decision in
the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024. 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 tax increased for the three and six months ended June
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.
Gain on sales of assets and businesses decreased for the six months ended June
30, 2022 compared to the same period in 2021, primarily due to a gain on sale of
our solar business in 2021.
Interest expense, net decreased for the three and six months ended June 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 six months ended
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Three Months Ended
2022 2021 2022 2021
Net unrealized (losses) gains on NDT funds(a)
63 52 248
Interest and dividend income on NDT funds(a) 29 28 48 46
Contractual elimination of income tax expense(b) (148) 97 (220) 139
Non-service net periodic benefit credit(c) 33 - 52 -
Net unrealized (losses) gains from equity
investments(d) (5) 119 (25) 96
Return to provision adjustment(e) (58) - (58) -
Other 25 6 30 18
Total Other, net $ (654) $ 508 $ (973) $ 675
_________
(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
will now be 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 equity 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.
Effective income tax rates were 74.9% and 88.7% for the three months ended June
30, 2022 and 2021, respectively, and 101.1% and 8.5% for the six months ended
June 30, 2022 and 2021, respectively. The change in effective tax rate in 2022
is primarily due to the impacts of higher unrealized NDT losses on Income before
income taxes. 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 six months ended June 30, 2022 and includes CENG and CRP for the
same period in 2021. The decrease for the three and six months ended June 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
OnFebruary 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 onFebruary 1, 2022 . We incurred separation costs of$31 million and$68 million for the three and six months endedJune 30, 2022 , respectively, which are primarily recorded in Operating and maintenance expense. Separation costs for the three and six months endedJune 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. 78
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Table of Contents Other Key Business Drivers Power MarketsRussia and Ukraine Conflict We are closely monitoring developments of theRussia andUkraine conflict includingUnited States sanctions against Russian energy exports, the potential for sanctions on Russian nuclear fuel supply, and enrichment activities, as well as yet undefined action byRussia to limit energy deliveries. Currently, our fuel supply has not been affected by theRussia andUkraine 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 withinthe 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 inIllinois , 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 ofJune 30, 2022 , the percentage of expected generation hedged for the Mid-Atlantic, Midwest,New York , andERCOT reportable segments is 95%-98% and 88%-91% 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 50% 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. Combating climate change is one of the top legislative agenda items of the Biden administration, with the President proposing a 100% clean energy economy with net zero GHG emissions by 2050 and to reduceU.S. emissions by 50% or more from 2005 levels by 2030. While consideration of the Build Back Better Act has stalled inCongress , SenatorJoe Manchin continues to express an openness to a smaller bill that includes climate-related provisions that include a production tax credit for clean power sources. OnJuly 27, 2022 , Senate Majority LeaderChuck Schumer and SenatorJoe Manchin announced that they have reached an agreement on budget reconciliation legislation, the Inflation Reduction Act of 2022, which, among other things, includes federal tax credits for a number of clean energy technologies including nuclear plants and hydrogen production facilities. We support federal tax credits that recognize the value of existing carbon-free nuclear plants and support the development of hydrogen solutions.The Biden Administration and members ofCongress have recognized the importance of existing nuclear power plants, which provide half 79
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of the nation's emissions-free energy, to meeting
Regulation of GHGs from Power Plants under the Clean Air Act. TheEPA 's 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants underClean 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. InJuly 2019 , theEPA 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 theU.S. Court of Appeals for the D.C. Circuit onSeptember 6, 2019 , challenging the Affordable Clean Energy rule as unlawful. OnJanuary 19, 2021 , theU.S. Court of Appeals for the D.C. Circuit vacated the Affordable Clean Energy Rule. OnOctober 29, 2021 , theSupreme Court granted certiorari to examine the extent ofEPA 's authority to regulate GHGs from power plants. The electric utilities coalition filed a brief and participated in oral argument before theSupreme Court . OnJune 30, 2022 , theSupreme Court issued a decision holding thatEPA 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. TheEPA has indicated it will promulgate new GHG limits for existing power plants inMarch 2023 . State Climate Change Legislation and Regulation. OnJuly 1, 2022 ,Pennsylvania formally began participation in the RGGI, joiningConnecticut ,Delaware ,Maine ,Maryland ,Massachusetts ,New Hampshire ,New Jersey ,New York ,Rhode Island ,Vermont , andVirginia . The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances. The process of bringingPennsylvania into the RGGI began inOctober 2019 when the Governor ofPennsylvania signed an Executive Order directing the PA DEP to commence the rulemaking to join the RGGI. OnJuly 8, 2022 , theCommonwealth Court of Pennsylvania entered a preliminary injunction preventingPennsylvania from participating in RGGI while ongoing legal challenges proceed. The PA DEP and we have appealed that decision. The injunction may be lifted during the appeal in which case the PA DEP's rule will remain effective through further court actions, and power plants inPennsylvania would be required to account for their CO2 emissions starting onJuly 1, 2022 andPennsylvania could auction allowances beginningSeptember 7, 2022 . Mercury and Air Toxics Standards (MATS). In 2011, theEPA 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. OnJanuary 20, 2021 ,President Biden issued an Executive Order directing theEPA to reconsider itsMay 22, 2020 , revised supplemental finding, and theEPA subsequently moved for theU.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 onFebruary 21, 2021 . OnFebruary 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, inFebruary 2022 , theU.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 dueApril 11, 2022 . IfEPA promulgates a final rule revoking the 2020 revised supplemental finding determination, then the cases currently before theU.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. 80
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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 plans 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
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 plans 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$5.7 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 onJanuary 31, 2022 . See Note 1 - Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation. 82
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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 required financial assurances, 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 ofJune 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 onApril 5, 2019 . OnOctober 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 onMay 20, 2021 . OnJune 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 six months ended
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