Constellation Energy Corp 10-Q

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions, unless otherwise noted) Executive Overview We are a supplier of clean energy. Our generating capacity includes 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 competitive 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 income (loss) for the three months ended March 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the three months ended March 31, 2022 and 2021 see the discussions of Results of Operations below. Three Months Ended March 31, Favorable (Unfavorable) Variance 2022 2021 GAAP Net income (loss) $ 106 $ (793) $ 899 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 income (loss) attributable to common shareholders as determined in accordance with GAAP and Adjusted EBITDA (non-GAAP) for the three months ended March 31, 2022 compared to the same period in 2021. 58 Table of Contents Three Months Ended March 31, 2022 2021 Net Income (Loss) Attributable to Common Shareholders $ 106 $ (793) Income Taxes (53) (179) Depreciation and Amortization (a) 280 940 Interest Expense, Net 56 72 Unrealized Loss/(Gain) on Fair Value Adjustments (b) 118 (131) Plant Retirements and Divestitures (c) — (3) Decommissioning-Related Activities (d) 354 (372) Pension & OPEB Non-Service Costs (25) (10) Separation Costs (e) 37 3 COVID-19 Direct Costs (f) — 12 Acquisition Related Costs (g) — 8 ERP System Implementation Costs (h) 5 2 Change in Environmental Liabilities — 3 Cost Management Program — 2 Noncontrolling Interests (i) (12) (19) Adjusted EBITDA (non-GAAP) $ 866 $ (465) __________ (a) In 2021, includes the accelerated depreciation associated with early plant retirements. (b) Includes mark-to-market on economic hedges and fair value adjustments relates to gas imbalances and equity investments. (c) Primarily reflects a gain on sale of our solar business, partially offset by accelerated nuclear fuel amortization for Byron and Dresden. (d) Reflects all gains and losses associated with NDTs, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units. (e) Represents costs related to the separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs. (f) 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. (g) Reflects costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021. (h) Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation. (i) Reflects elimination from results for the noncontrolling interests related to certain adjustments, primarily relating to CRP in 2022 and CENG in 2021. 59 Table of Contents Results of Operations Three Months Ended March 31, Favorable (Unfavorable) Variance 2022 2021 Operating revenues $ 5,591 $ 5,559 $ 32 Operating expenses Purchased power and fuel 3,550 4,610 1,060 Operating and maintenance 1,205 1,001 (204) Depreciation and amortization 280 940 660 Taxes other than income taxes 137 121 (16) Total operating expenses 5,172 6,672 1,500 Gain on sales of assets and businesses 16 71 (55) Operating income (loss) 435 (1,042) 1,477 Other income and (deductions) Interest expense, net (56) (72) 16 Other, net (318) 167 (485) Total other income and (deductions) (374) 95 (469) Income (loss) before income taxes 61 (947) 1,008 Income taxes (53) (179) (126) Equity in losses of unconsolidated affiliates (3) (1) (2) Net income (loss) 111 (769) 880 Net income attributable to noncontrolling interests 5 24 (19) Net income (loss) attributable to common shareholders $ 106 $ (793) $ 899 Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income attributable to common shareholders increased by $899 million primarily due to: • The absence of impacts from the February 2021 extreme cold weather event; • 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; • 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; • Absence of a prior year gain on the sale of our solar business; • Increased tax expense due to one-time items related to the separatio n; • Decreased capacity revenues; and • Unfavorable impacts from nuclear outages. 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 60 Table of Contents 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. 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 months ended March 31, 2022 compared to 2021, Operating revenues by region were as follows: Three Months Ended March 31, 2022 2021 Variance % Change (a) Mid-Atlantic $ 1,104 $ 1,165 $ (61) (5.2) % Midwest 1,197 998 199 19.9 % New York 365 337 28 8.3 % ERCOT 235 257 (22) (8.6) % Other Power Regions 1,927 1,430 497 34.8 % Total electric revenues 4,828 4,187 641 15.3 % Other 1,684 1,456 228 15.7 % Mark-to-market losses (921) (84) (837) Total Operating revenues $ 5,591 $ 5,559 $ 32 0.6 % __________ (a) % Change in mark-to-market is not a meaningful measure. 61 Table of Contents Sales and Supply Sources. Our sales and supply sources by region are summarized below: Three Months Ended March 31, Supply Source (GWhs) 2022 2021 Variance % Change Nuclear Generation (a) Mid-Atlantic 13,123 13,254 (131) (1.0) % Midwest 23,462 23,155 307 1.3 % New York 6,366 7,057 (691) (9.8) % Total Nuclear Generation 42,951 43,466 (515) (1.2) % Natural Gas, Oil, and Renewables Mid-Atlantic 727 662 65 9.8 % Midwest 366 323 43 13.3 % New York — 1 (1) (100.0) % ERCOT 2,974 2,783 191 6.9 % Other Power Regions 2,902 2,964 (62) (2.1) % Total Natural Gas, Oil, and Renewables 6,969 6,733 236 3.5 % Purchased Power Mid-Atlantic 2,772 4,483 (1,711) (38.2) % Midwest 196 179 17 9.5 % ERCOT 736 772 (36) (4.7) % Other Power Regions 13,655 12,834 821 6.4 % Total Purchased Power 17,359 18,268 (909) (5.0) % Total Supply/Sales by Region Mid-Atlantic 16,622 18,399 (1,777) (9.7) % Midwest 24,024 23,657 367 1.6 % New York 6,366 7,058 (692) (9.8) % ERCOT 3,710 3,555 155 4.4 % Other Power Regions 16,557 15,798 759 4.8 % Total Supply/Sales by Region 67,279 68,467 (1,188) (1.7) % __________ (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. 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. Three Months Ended March 31, 2022 2021 Nuclear fleet capacity factor (a) 93.0 % 94.2 % Refueling outage days 76 84 Non-refueling outage days 10 3 __________ (a) Prior year capacity factor was previously reported as 95.3%. 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. 62 Table of Contents ZEC Prices. We are compensated through state programs for the carbon-free attributes of our nuclear generation. ZEC prices have a significant impact on operating revenues. The following table presents the average 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 March 31, State (Region) (a) 2022 2021 Variance % Change New Jersey (Mid-Atlantic) $ 10.00 $ 10.00 $ — — % Illinois (Midwest) 16.50 16.50 — — % New York (New York) 21.38 19.59 1.79 9.1 % __________ (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. 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, except in ERCOT. 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 March 31, Location (Region) 2022 2021 Variance % Change Eastern Mid-Atlantic Area Council (Mid-Atlantic and Midwest) $ 165.73 $ 187.87 $ (22.14) (11.8) % ComEd (Midwest) 195.55 188.12 7.43 3.9 % Rest of State (New York) 85.11 13.02 72.09 553.7 % Southeast New England (Other) 154.37 176.67 (22.30) (12.6) % 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 March 31, Location (Region) 2022 2021 Variance % Change PJM West (Mid-Atlantic) $ 55.39 $ 30.60 $ 24.79 81.0 % ComEd (Midwest) 40.25 28.52 11.73 41.1 % Central (New York) 65.95 25.24 40.71 161.3 % North (ERCOT) 37.04 476.74 (439.70) (92.2) % Southeast Massachusetts (Other) (a) 111.62 49.88 61.74 123.8 % __________ (a) Reflects New England, which comprises the majority of the activity in the Other region. 63 Table of Contents For the three months ended March 31, 2022 compared to 2021, changes in Operating revenues by region were approximately as follows: Variance % Change (a) Three Months Ended March 31, 2022 Mid-Atlantic $ (61) (5.2) % • unfavorable wholesale load revenue of ($105) primarily due to lower volumes partially offset by higher energy prices • unfavorable settled economic hedges of ($45) due to settled prices relative to hedged prices; partially offset by • favorable retail load revenue of $95 primarily due to higher energy prices Midwest 199 19.9 % • favorable net wholesale load and generation revenue of $220 primarily due to higher energy prices and higher volumes, partially offset by lower cleared capacity volumes; partially offset by • unfavorable settled economic hedges of ($40) due to settled prices relative to hedged prices New York 28 8.3 % • favorable retail load revenue of $75 primarily due to higher energy prices and higher volumes • favorable generation revenue of $55 primarily due to higher energy prices; partially offset by • unfavorable settled economic hedges of ($110) due to settled prices relative to hedged prices ERCOT (22) (8.6) % • unfavorable retail load revenue of ($105) and wholesale load revenue of ($70) primarily due to lower energy prices relative to the prior year due to the February 2021 extreme cold weather event; partially offset by • favorable settled economic hedges of $160 due to settled prices relative to hedged prices Other Power Regions 497 34.8 % • favorable settled economic hedges of $195 due to settled prices relative to hedged prices • favorable wholesale load revenue of $195 primarily due to higher energy prices and higher volumes • favorable retail load revenue of $100 primarily due to higher energy prices and higher volumes Other 228 15.7 % • favorable gas revenue of $320 primarily due to higher gas prices • favorable energy revenue of $110 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 ($200) Mark-to-market (b) (837) • losses on economic hedging activities of ($921) in 2022 compared to losses of ($84) in 2021 Total $ 32 0.6 % __________ (a) % Change in mark-to-market is not a meaningful measure. (b) See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses. 64 Table of Contents 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 months ended March 31, 2022 compared to 2021, Purchased power and fuel by region were as follows: Three Months Ended March 31, 2022 2021 Variance % Change (a) Mid-Atlantic $ 596 $ 599 $ 3 0.5 % Midwest 412 296 (116) (39.2) % New York 97 95 (2) (2.1) % ERCOT 156 1,441 1,285 89.2 % Other Power Regions 1,640 1,213 (427) (35.2) % Total electric purchased power and fuel 2,901 3,644 743 20.4 % Other 1,478 1,225 (253) (20.7) % Mark-to-market gains (829) (259) 570 Total purchased power and fuel $ 3,550 $ 4,610 $ 1,060 23.0 % __________ (a) % Change in mark-to-market is not a meaningful measure. 65 Table of Contents For the three months ended March 31, 2022 compared to 2021, changes in Purchased power and fuel by region were approximately as follows: Variance % Change (a) Three Months Ended March 31, 2022 Mid-Atlantic $ 3 0.5 % • no significant changes Midwest (116) (39.2) % • unfavorable purchased power of ($140) primarily due to higher energy prices and higher load; partially offset by • favorable nuclear fuel cost of $35 primarily due to accelerated amortization of nuclear fuel in prior periods New York (2) (2.1) % • favorable settlement of economic hedges of $25 due to settled prices relative to hedged prices; partially offset by • unfavorable purchased power and net capacity impact of ($25) primarily due to higher energy prices and lower nuclear generation partially offset by higher capacity prices earned ERCOT 1,285 89.2 % • favorable purchased power of $830 primarily due to lower energy prices relative to the prior year due to the February 2021 extreme cold weather event • favorable settlement of economic hedges of $310 due to settled prices relative to hedged prices • favorable fuel cost of $130 primarily due to lower gas prices relative to the prior year due to the February 2021 extreme cold weather event Other Power Regions (427) (35.2) % • unfavorable purchased power and net capacity impact of ($680) primarily due to higher energy prices and higher load • unfavorable fuel cost of ($245) primarily due to higher gas prices; partially offset by • favorable settlement of economic hedges of $535 due to settled prices relative to hedged prices Other (253) (20.7) % • unfavorable net gas purchase costs and settlement of economic hedges of ($550) • unfavorable energy purchases of ($85) primarily due to higher energy prices; partially offset by • favorable impact due to the absence of LDC and pipeline penalties due to the February 2021 extreme cold weather event of $325M • favorable impact due to the absence of accelerated nuclear fuel amortization associated with announced early plant retirements of $55 Mark-to-market (b) 570 • gains on economic hedging activities of $829 in 2022 compared to gains of $259 in 2021 Total $ 1,060 23.0 % __________ (a) % Change in mark-to-market is not a meaningful measure. (b) See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses. 66 Table of Contents The changes in Operating and maintenance expense consisted of the following: Three Months Ended March 31, 2022 Increase (Decrease) Decommissioning-related activities (a) $ 223 Nuclear refueling outage costs, including the co-owned Salem generating units 29 Labor, other benefits, contracting, and materials (10) Credit loss expense (b) (42) Other 4 Total increase $ 204 __________ (a) 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. (b) Primarily a result of the February 2021 extreme cold weather event. Depreciation and amortization expense decreased for the three months ended March 31, 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. Gain on sales of assets and businesses decreased for the three months ended March 31, 2022 compared to the same period in 2021, primarily due to a gain on sale of our solar business in 2021. Inte res t expense, net decreased for the three months ended March 31, 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. See Note 17 — Debt and Credit Agreements of our 2021 Form 10K of the Combined Notes to Consolidated Financial Statements for additional information on the CR credit facility and interest rate swaps. Other, net decreased for the three months ended March 31, 2022 compared to the same period in 2021, due to activity described in the table below: Three Months Ended March 31, 2022 2021 Net unrealized losses on NDT funds (a) $ (337) $ (66) Net realized gains on sale of NDT funds (a) 66 185 Interest and dividend income on NDT funds (a) 19 18 Contractual elimination of income tax expense (b) (72) 42 Non-service net periodic benefit cost (c) 18 — Net unrealized losses from equity investments (d) (20) (23) Other 8 11 Total Other, net $ (318) $ 167 _________ (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 costs from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service cost components will now be included in Other, net, in accordance with single employer plan accounting. See Note 10 — Retirement Benefits 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. 67 Table of Contents Effective income tax rates were (86.9)% and 18.9% for the three months ended March 31, 2022 and 2021, respectively. The change in effective tax rate in 2022 is primarily due to the impacts of higher net realized and unrealized NDT losses on Income before income taxes. S ee Note 9 — 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 months ended March 31, 2022 and includes CENG and CRP for the three months ended March 31, 2021. The decrease for the three months ended March 31, 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 $37 million for the three months ended March 31, 2022, which are primarily recorded in Operating and maintenance expense. Separation costs for the three months ended March 31, 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. 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. Currently, none of our existing nuclear fuel contracts have 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 March 31, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 97%-100% and 86%-89% for the remainder of 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 68 Table of Contents 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 11 — 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 State Climate Change Legislation and Regulation. Eleven northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia) currently participate in the RGGI, which is in the process of strengthening its requirements. 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. In October 2019, the Governor of Pennsylvania issued an Executive Order directing the PA DEP to begin a rulemaking process to allow Pennsylvania to join the RGGI, with the goal of reducing carbon emissions from the electricity sector. The Environmental Quality Board of the PA DEP approved that rule on July 13, 2021, and on April 23, 2022, the rule was published by the Pennsylvania Legislative Resource Bureau, which made the rule effective. Although outstanding legal challenges remain, the conclusion of the regulatory process enables Pennsylvania’s participation in RGGI beginning July 2022. 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. Critical Accounting Policies and Estimates Management makes a number of significant estimates, assumptions, and judgements in the preparation of our financial statements. At March 31, 2022, 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 69 Table of Contents 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. 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 10 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements, while holding all other assumptions constant: Actual Assumption Pension OPEB Assumption Increase / (Decrease) Actuarial 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. 70 Table of Contents See Note 1 — Basis of Presentation and Note 10 — 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 12 — 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. 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 of March 31, 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 71 Table of Contents 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 and is pending NRC review. 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 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation. The following table provides a summary of the change in cash flows from operating activities for the three months ended March 31, 2022 and 2021: Increase (decrease) in cash flows from operating activities Net income $ 880 Adjustments to reconcile net income to cash: Non-cash operating activities 214 Option premiums (paid) received, net (47) Collateral posted, net 899 Income taxes 309 Pension and non-pension postretirement benefit contributions 1 Changes in working capital and other noncurrent assets and liabilities 695 Increase in cash flows from operating activities $ 2,951 Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the three months ended March 31, 2022 and 2021 were as follows: • See Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Consolidated Statements of Cash Flows for additional information on non-cash operating activities . • Option premiums paid relate to options contracts that we purchase and sell as part of our established policies and procedures to manage risks associated with market fluctuations in commodity prices. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on derivative contracts. • Depending upon whether we are in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from our counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the over-the-counter markets. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral. • See Note 9 —Income Taxes of the Combined Notes to Consolidated Financial Statements and the Consolidated Statements of Cash Flows for additional information on income taxes. • Changes in working capital and other noncurrent assets and liabilities primarily reflect reduced DPP consideration related to the revolving accounts receivable financing arrangement entered into on April 8, 2020. There is a partial offset for this increase in Cash Flows from Investing activities due to cash proceeds received from the Purchasers during the first quarter of 2021. and a decrease in Accounts payable and accrued expenses resulting from the impact of certain penalties for natural gas delivery associated with the February 2021 extreme cold weather event and decreases in natural gas prices. See Note 6 — Accounts Receivable and Note 3 — Regulatory Matters of the Combined Notes 72 Table of Contents to Consolidated Financial Statements for additional information on the sales of customer accounts receivable and on the February 2021 extreme cold weather event, respectively. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the three months ended March 31, 2022 and 2021: Decrease in cash flows from investing activities Capital expenditures $ (28) Investment in NDT fund sales, net (32) Collection of DPP (721) Proceeds from sales of assets and businesses (652) Other investing activities (2) Decrease in cash flows from investing activities $ (1,435) Significant investing cash flow impacts for the three months ended March 31, 2022 and 2021 were as follows: • Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer to Liquidity and Capital Resources of our 2021 Form 10-K for additional information on projected capital expenditure spending, of which there have been no material changes to the projected amounts. • See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the Collection of DPP . • Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of our solar business. See Note 2 — Mergers, Acquisitions, and Dispositions of the Notes to Consolidated Financial Statements for additional information on the sale of our solar business. Cash Flows from Financing Activities The following table provides a summary of the change in cash flows from financing activities for the three months ended March 31, 2022 and 2021: (Decrease) increase in cash flows from financing activities Changes in short-term borrowings, net $ (1,999) Long-term debt, net (1,280) Changes in money pool with Exelon 285 Distributions to member 412 Contribution from Exelon 1,750 Other financing activities (11) Decrease in cash flows from financing activities $ (843) Significant financing cash flow impacts for the three months ended March 31, 2022 and 2021 were as follows: • Changes in short-term borrowings, net , is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 12 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings. • Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to Note 12 - Debt and Credit Agreements below for additional information. • Changes in money pool with Exelon were driven by short-term borrowing needs prior to the separation on February 1, 2022. Exelon operated a money pool for its subsidiaries that provided an additional short-term borrowing option that was generally more favorable to the borrowing participants than the cost of external financing. 73 Table of Contents • Contribution from Exelon is related to a cash contribution of $1.75 billion from Exelon on January 31, 2022, pursuant to the Separation Agreement. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation. Dividends Quarterly dividends declared by our Board of Directors during the three months ended March 31, 2022 and for the second quarter of 2022 were as follows: Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share (a) First Quarter of 2022 February 8, 2022 February 25, 2022 March 10, 2022 $ 0.1410 Second Quarter of 2022 April 26, 2022 May 13, 2022 June 10, 2022 $ 0.1410 Credit Matters and Cash Requirements We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of March 31, 2022, we have access to facilities with aggregate bank commitments of $5.7 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during the first quarter of 2022 to fund our short-term liquidity needs, when necessary. We used our available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2021 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets. We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below. If we lost our investment grade credit rating as of March 31, 2022, we would have been required to provide incremental collateral of up to approximately $2.8 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which was well within the combined amount of $2.6 billion of available capacity and $1.7 billion of cash on hand as of March 31, 2022. See Note 11 — Derivative Financial Instruments and Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Pension and Other Postretirement Benefits We consider various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), and management of the pension obligation. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are both subject to change, we made our annual qualified pension contribution totaling $192 million in February 2022. Unlike the qualified pension plans, our non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements. While OPEB plans are also not subject to statutory minimum contribution requirements, we do fund certain of our plans. For our funded OPEB plans, contributions generally equal accounting costs; however, we consider several factors in determining the level of contributions to our OPEB plans, including liabilities management and levels of benefit claims paid. The planned benefit payments to the non-qualified pension plans in 2022 are $9 million and the planned contributions to the OPEB plans, including benefit payments to unfunded plans is $27 million. The 74 Table of Contents benefit payments to the non-qualified pension plans and OPEB plans for the three months ended March 31, 2022 were both $6 million. To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if we change our pension or OPEB funding strategy. See Note 10 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions. Cash Requirements for Other Financial Commitments Refer to Liquidity and Capital Resources of our 2021 Form 10-K for additional information on our cash requirements for financial commitments. Sales of Customer Accounts Receivable We have an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables, which expires on March 29, 2024 unless renewed by the mutual consent of the parties in accordance with its terms. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. Project Financing Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by a specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. Lenders do not have recourse against us in the event of a default. If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to repay the debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. See Note 17 — Debt and Credit Agreements of the Notes to Consolidated Financial Statements of our 2021 Form 10-K for additional information on our project finance structures and nonrecourse debt. Credit Facilities We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities. Security Ratings Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings. Our borrowings are not subject to default or prepayment as a result of a downgrade of our securities, although such a downgrade could increase fees and interest charges under our facility agreements. As part of the normal course of business, we enter into contracts that contain express provisions or otherwise permit us and our counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if we are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of additional collateral. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions. 75 Table of Contents At separation S&P and Moody's affirmed our senior unsecured ratings of BBB- and Baa2, respectively. Fitch also affirmed their final rating of BBB, prior to formally withdrawing coverage on January 5th. We will only be engaging S&P and Moody's for ratings coverage following separation.