# Constellation Energy Corp (CEG) FY 2022 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Constellation Energy Corp's 10-K for fiscal year 2022.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1868275/000186827523000014/ceg-20221231.htm
Accession: 0001868275-23-000014
Filing date: 2023-02-16
Report date: 2022-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/CEG/
All MD&A years: /company/CEG/mda/
Previous year: /company/CEG/mda/fy2021/ (FY 2021)
Next year: /company/CEG/mda/fy2023/ (FY 2023)

Item 7. 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 primarily consists of 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. The following Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2022 compared to the year ended December 31, 2021. For discussion of the year ended December 31, 2021 compared to the year ended December 31, 2020, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2021 Form 10-K, which was filed with the SEC on February 25, 2022.

Capital Allocation and Growth Announcements

We are announcing our capital allocation strategy for 2023 and 2024 supporting our core principles outlined in our Strategy and Outlook discussion. See ITEM 1. BUSINESS – Constellation's Strategy and Outlook for additional information about our strategy.

We will double the annual dividend in 2023 from $0.5640 per share to $1.1280 per share while targeting growth of 10% annually. We are allocating capital towards our best-in-class generation fleet by committing $1.5 billion of growth capital expenditures over the next three years, including nuclear uprates, wind repowering and hydrogen. These organic growth opportunities are projected to exceed our double-digit return threshold. In our commitment to return value to shareholders, we have also authorized a share buyback program of $1.0 billion.

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. In order to govern the ongoing relationships between us and Exelon after the separation, and to facilitate an orderly transition, we and Exelon have entered into several agreements, including a Separation Agreement, Tax Matters Agreement, a Transition Services Agreement, and an Employee Matters Agreement and other ancillary agreements. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information.

We incurred separation costs of $140 million and $49 million for the twelve months ended December 31, 2022 and 2021, respectively, which are primarily recorded in Operating and maintenance expense. We expect to incur incremental costs of approximately $80 million in 2023. 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.

PJM Performance Bonuses

On December 23, 2022, and continuing through the morning of December 25, 2022, winter storm Elliott blanketed the entirety of PJM’s footprint with record low temperatures and extreme weather conditions. A significant portion of PJM's fossil generation fleet failed to perform as reserves were called. PJM’s initial estimate of non-performance charges ranges from $1 billion to $2 billion and, in accordance with its tariff, funds collected from those charges are redistributed to generating resources that performed above expectations during the event. PJM released preliminary invoices to generators subject to non-performance charges and bonuses on February 10, 2023. PJM indicated that these preliminary invoices are informational and subject to change for items that could have a material impact to the final amounts billed to non-performing generators, pending PJM’s

49

Table of Contents

completion of their internal processes and data quality assurance reviews. Leveraging preliminary data from PJM and applying significant judgments and assumptions, we recognized an estimated benefit of $109 million (pre-tax) for performance bonuses (net of non-performance charges), primarily driven by the overperformance of our nuclear fleet. The ultimate impact to our consolidated financial statements may be affected by several factors, including final non-performance charges billed, the impacts of generator defaults, and related litigation and disputes. It is reasonably possible that the ultimate benefit could differ significantly once these uncertainties are resolved, which could have a material impact on our financial statements.

Other Key Business Drivers

Russia and Ukraine Conflict

We are closely monitoring developments of the Russia and Ukraine conflict including United States sanctions against Russian energy exports, the potential for sanctions on Russian nuclear fuel supply, and enrichment activities, as well as yet undefined action by Russia to limit energy deliveries. To-date, our nuclear fuel deliveries have not been affected by the Russia and Ukraine conflict. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel and generally have enough nuclear fuel to support all our refueling needs for multiple years regardless of sanctions. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. We are taking this 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 and provide the necessary fuel to bridge potential Russian supply disruption through 2028, which is the date multiple suppliers are expected to have incremental capacity online. We are also continuing to work 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 typically 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 December 31, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, 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 60% of our uranium concentrate requirements from 2023 through 2027 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, including the Russia and Ukraine conflict and United States sanctions against Russia, 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 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

50

Table of Contents

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the consolidated financial statements. Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

Nuclear Decommissioning Asset Retirement Obligations

The AROs associated with decommissioning our nuclear units were $12.5 billion at December 31, 2022. The authoritative guidance requires that we estimate our obligation for the future decommissioning of our nuclear generating plants. To estimate that liability, we use an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios.

As a result of nuclear plant retirements in the industry, in recent years, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The amount of NDT funds could also impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to our current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.

The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:

Decommissioning Cost Studies. We use unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, we evaluate newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.

Cost Escalation Factors. We use cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal, and other costs. All the nuclear AROs are adjusted each year for updated cost escalation factors.

Probabilistic Cash Flow Models. Our probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The assumed decommissioning scenarios generally include the following three alternatives: (1) DECON, which assumes major decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR, which generally assumes a 30-year delay prior to onset of major decommissioning activities, and (3) SAFSTOR, which assumes the nuclear facility is placed and maintained in such condition during decommissioning so that the nuclear facility can be safely stored and subsequently decontaminated within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.

51

Table of Contents

The actual decommissioning approach selected will be determined at the time of shutdown and may be influenced by multiple factors including the funding status of the NDT funds at the time of shutdown and regulatory or other commitments.

The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an initial 20-year license renewal term, (3) the probability of a second, 20-year license renewal term, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. As power market and regulatory environment developments occur, we evaluate and incorporate, as necessary, the impacts of such developments into our nuclear ARO assumptions and estimates.

Our probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. We currently assume DOE will begin accepting SNF from the industry in 2035. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding SNF, see Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. We initially recognize an ARO at fair value and subsequently adjust it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO due to upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR rates used in creating the initial ARO cost layers. If all our future nominal cash flows associated with the ARO were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $12.5 billion to approximately $10.5 billion.

The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO:

[[GREPCENT_TABLE]]
[["Change in the CARFR applied to the annual ARO update","Increase (Decrease) to ARO as of December 31, 2022"],["2021 CARFR rather than the 2022 CARFR","$","3,470"],["2022 CARFR increased by 50 basis points","(570)"],["2022 CARFR decreased by 50 basis points","710"]]
[[/GREPCENT_TABLE]]

52

Table of Contents

ARO Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact of a change in any one of these assumptions to the ARO is highly dependent on how the other assumptions may correspondingly change.

The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant:

[[GREPCENT_TABLE]]
[["Change in ARO Assumption","Increase (Decrease) to ARO as of December 31, 2022"],["Cost escalation studies"],["Uniform increase in escalation rates of 50 basis points","$","1,780"],["Probabilistic cash flow models"],["Increase the estimated costs to decommission the nuclear plants by 10 percent","720"],["Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent(a)","140"],["Shorten each unit's probability weighted operating life assumption by 10 percent(b)","280"],["Extend the estimated date for DOE acceptance of SNF to 2040","(70)"]]
[[/GREPCENT_TABLE]]

__________

(a)Excludes any sites in which management has committed to a specific decommissioning approach.

(b)Excludes any retired sites.

See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs.

Unamortized Energy Contract Assets and Liabilities

Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that we have acquired. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. The unamortized energy contract assets and liabilities are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract assets and liabilities are recorded through Operating revenues or Purchased power and fuel expense, depending on the nature of the underlying contract. See Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Impairment of Long-Lived Assets

We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life.

The review of long-lived assets or asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. Forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. The lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units. The cash flows from our generating units are generally evaluated at a regional portfolio level (asset group) given the interdependency of cash flows generated from the customer supply and risk management activities within each region. In certain cases, our generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third-party and operations are independent of other generating assets (typically contracted renewables).

53

Table of Contents

On a quarterly basis, we assess our long-lived assets or asset groups for indicators of potential impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the asset or asset groups. This includes significant assumptions of the estimated future cash flows generated by the asset or asset groups and market discount rates. Events and circumstances often do not occur as expected, resulting in differences between prospective financial information and actual results, which may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3), such as revenue and generation forecasts, projected capital, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources.

See Note 12 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment assessments.

Depreciable Lives of Property, Plant and Equipment

We have significant investments in electric generation assets. These assets are generally depreciated on a straight-line basis, using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are generally conducted periodically if an event, regulatory action, or change in retirement patterns indicate an update is necessary.

Along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of our generating facilities and reassesses the reasonableness of estimated useful lives whenever events or changes in circumstances warrant. When a determination has been made that an asset will be retired before the end of its current estimated useful life, depreciation provisions will be accelerated to reflect the shortened estimated useful life, which could have a material unfavorable impact on future results of operations. See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.

Changes in estimated useful lives of electric generation assets could have a significant impact on future results of operations. See Note 1 — Basis of Presentation and Note 8 — Property, Plant, and Equipment of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant and equipment.

Accounting for Derivative Instruments

We use derivative instruments to manage commodity price risk, foreign currency exchange risk and interest rate risk related to ongoing business operations. Our derivative activities are in accordance with our Risk Management Policy (RMP). See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

We account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope of new authoritative guidance.

All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives entered for economic hedging and for proprietary trading purposes are recorded at fair value through earnings.

54

Table of Contents

NPNS. As part of our energy marketing business, we enter contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated as NPNS transactions, and are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements. Contracts that qualify for NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period, and the contract is not financially settled on a net basis. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed.

Commodity Contracts. Identification of a commodity contract as an economic hedge requires us to determine that the contract is in accordance with the RMP. We reassess our economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.

As a part of the authoritative guidance, we make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, we categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.

Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy.

Certain derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, online exchanges. The price quotations reflect the average of the mid-point of the bid-ask spread from observable markets that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. Our derivatives are traded predominantly at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of commodities, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the model inputs are generally observable. Such instruments are categorized in Level 2.

For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.

We consider nonperformance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in our assessment of nonperformance risk. The impacts of nonperformance and credit risk to date have generally not been material to the consolidated financial statements.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 18 — Fair Value of Financial Assets and Liabilities and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative instruments.

Defined Benefit Pension and Other Postretirement Employee Benefits

We sponsor defined benefit pension and OPEB plans for most current employees. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, we consider historical information as well as future expectations. The measurement of projected benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, our contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations.

55

Table of Contents

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, private credit, and hedge funds.

Expected Rate of Return on Plan Assets. In determining the EROA, we consider expectations 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. At separation and upon remeasurement as of December 31, 2022, we utilized the 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 and as discussed in Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements, while holding all other assumptions constant:

[[GREPCENT_TABLE]]
[["","Actual Assumption"],["","Pension","OPEB","Assumption","","Increase / (Decrease)"],["Actuarial Assumption","","Pension","","OPEB","","Total"],["Change in 2023 cost:"],["Discount rate(a)","5.52","%","5.50","%","0.5","%","","$","(13)","","","$","(1)","","","$","(14)"],["","5.52","%","5.50","%","(0.5)","%","","16","","","2","","","18"],["EROA","6.50","%","6.50","%","0.5","%","","(40)","","","(4)","","","(44)"],["","6.50","%","6.50","%","(0.5)","%","","40","","","4","","","44"],["Change in benefit obligation:"],["Discount rate(a)","5.52","%","5.50","%","0.5","%","","(345)","","","(61)","","","(406)"],["","5.52","%","5.50","%","(0.5)","%","","391","","","69","","","460"]]
[[/GREPCENT_TABLE]]
__________

(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 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension and OPEB plans.

56

Table of Contents

Taxation

Significant management judgment is required in determining our provision for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. We account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the consolidated financial statements.

We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and our intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. We also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate our inability to realize our deferred tax assets. Based on the combined assessment, we record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, our forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Accounting for Loss Contingencies

In the preparation of our financial statements, we make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the consolidated financial statements.

Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which we will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. In addition, periodic reviews are performed to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Other, Including Personal Injury Claims. Prior to our separation from Exelon, we were self-insured for general liability, automotive liability, and workers’ compensation claims. Upon separation, we now maintain insurance coverage for general liability, automotive liability, and workers’ compensation and are self-insured to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. For personal injury claims, we are self-insured to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. We have reserves for both open claims asserted, and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to the consolidated financial statements.

Revenue Recognition

Sources of Revenue and Determination of Accounting Treatment. We earn revenue from various business activities including: the sale of power and energy-related products, such as natural gas, capacity, and other

57

Table of Contents

commodities in non-regulated markets (wholesale and retail) and the provision of other energy-related non-regulated products and services.

The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. We primarily apply the Revenue from Contracts with Customers and Derivatives Revenues guidance to recognize revenue, as discussed in more detail below.

Revenue from Contracts with Customers. We recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas and other energy-related commodities and services are provided to the customer. Transactions within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS and spot-market energy commodity sales, including settlements with ISOs.

The determination of our retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly. Energy delivered to customers that has not yet been billed as of the reporting period is estimated and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is based upon individual customer meter readings, forecasted volumes, and applicable rates. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information.

Derivative Revenues. We record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth our GAAP consolidated Net Loss Attributable to Common Shareholders for the twelve months ended December 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the twelve months ended December 31, 2022 and 2021 see the discussions of Results of Operations below.

[[GREPCENT_TABLE]]
[["","Twelve Months Ended December 31,","Favorable Variance"],["","2022","","2021"],["GAAP Net Loss Attributable to Common Shareholders","$","(160)","","","$","(205)","","","$","45"]]
[[/GREPCENT_TABLE]]

Adjusted EBITDA (non-GAAP). In analyzing and planning for our business, we supplement our use of GAAP Net Loss Attributable to Common Shareholders 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 Loss Attributable to Common Shareholders 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.

58

Table of Contents

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 twelve months ended December 31, 2022 compared to the same period in 2021.

[[GREPCENT_TABLE]]
[["","","Twelve Months Ended December 31,"],["","","2022","","2021"],["Net Loss Attributable to Common Shareholders","","$","(160)","","","$","(205)"],["Income Taxes(a)","","(339)","","","225"],["Depreciation and Amortization(b)","","1,091","","","3,003"],["Interest Expense, Net","","251","","","297"],["Unrealized Loss (Gain) on Fair Value Adjustments(c)","","1,058","","","(420)"],["Asset Impairments(d)","","\u2014","","","541"],["Plant Retirements and Divestitures","","(11)","","","(4)"],["Decommissioning-Related Activities(e)","","820","","","(1,289)"],["Pension & OPEB Non-Service Credits","","(116)","","","(50)"],["Separation Costs(f)","","140","","","49"],["COVID-19 Direct Costs(g)","","\u2014","","","35"],["Acquisition-Related Costs(h)","","\u2014","","","21"],["ERP System Implementation Costs(i)","","22","","","14"],["Change in Environmental Liabilities","","10","","","12"],["Cost Management Program","","\u2014","","","9"],["Prior Merger Commitment(j)","","(50)","","","\u2014"],["Noncontrolling Interests(k)","","(49)","","","(53)"],["Adjusted EBITDA (non-GAAP)","","$","2,667","","","$","2,185"]]
[[/GREPCENT_TABLE]]
__________

(a)In 2022, includes amounts contractually owed to Exelon under the Tax Matters Agreement (TMA) 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 the New England asset group, an impairment recorded as a result of the sale of the Albany Green Energy biomass facility, and impairment of a wind project.

(e)Reflects all gains and losses associated with NDTs, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units.

(f)Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the Transition Services Agreement (TSA).

(g)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.

(h)Reflects costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021.

(i)Reflects costs related to a multi-year ERP system implementation.

(j)Reversal of a charge related to a prior 2012 merger commitment.

(k)Reflects elimination from results for the noncontrolling interests related to certain adjustments. In 2022, primarily relates to CRP and in 2021, primarily relates to CENG and the noncontrolling interest portion of a wind project impairment recognized within CRP.

59

Table of Contents

Results of Operations

[[GREPCENT_TABLE]]
[["","2022","","2021","","Favorable (Unfavorable) Variance"],["Operating revenues","$","24,440","","","$","19,649","","","$","4,791"],["Operating expenses"],["Purchased power and fuel","17,462","","","12,163","","","(5,299)"],["Operating and maintenance","4,841","","","4,555","","","(286)"],["Depreciation and amortization","1,091","","","3,003","","","1,912"],["Taxes other than income taxes","552","","","475","","","(77)"],["Total operating expenses","23,946","","","20,196","","","(3,750)"],["Gain on sales of assets and businesses","1","","","201","","","(200)"],["Operating income (loss)","495","","","(346)","","","841"],["Other income and (deductions)"],["Interest expense, net","(251)","","","(297)","","","46"],["Other, net","(786)","","","795","","","(1,581)"],["Total other income and (deductions)","(1,037)","","","498","","","(1,535)"],["(Loss) income before income taxes","(542)","","","152","","","(694)"],["Income taxes","(388)","","","225","","","613"],["Equity in losses of unconsolidated affiliates","(13)","","","(10)","","","(3)"],["Net loss","(167)","","","(83)","","","(84)"],["Net (loss) income attributable to noncontrolling interests","(7)","","","122","","","(129)"],["Net loss attributable to common shareholders","$","(160)","","","$","(205)","","","$","45"]]
[[/GREPCENT_TABLE]]

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021. Net loss attributable to common shareholders was favorable by $45 million primarily due to:

•The absence of accelerated depreciation and amortization associated with our previous decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021, and the absence of the reversal of charges recorded in the third quarter of 2021 associated with the reversal of the previous decision;

•The absence of impacts from the February 2021 extreme cold weather event;

•The absence of impairments of the New England asset group, the Albany Green Energy biomass facility, and a wind project;

•Impact of our annual update to the nuclear ARO for Non-Regulatory Agreement Units;

•Lower nuclear fuel costs primarily due to the absence of accelerated amortization of nuclear fuel and lower prices;

•Higher realized energy prices;

•Favorable PJM performance bonus payment, net of non-performance charges;

•The reversal of a charge related to a 2012 prior merger commitment; and

•Favorable impacts of nuclear outages.

The favorable items were partially offset by:

•Unfavorable mark-to-market activity;

•Unfavorable net realized and unrealized NDT activity;

60

Table of Contents

•Lower capacity revenues;

•Higher labor, contracting and materials;

•Unfavorable impact of net realized and unrealized CTV investment activity;

•Higher separation costs;

•Lower NEIL distributions; and

•The absence of a prior year gain on the sale of our solar business.

Operating revenues. The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned with these same geographic regions. Our five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.

The following business activities are not allocated to a region and are reported under Other: wholesale and retail sales of natural gas, as well as other miscellaneous business activities that are not significant to overall results of operations.

For the year ended December 31, 2022 compared to 2021, Operating revenues by region were as follows:

[[GREPCENT_TABLE]]
[["","","","","","2022 vs. 2021"],["","2022","","2021","","Variance","","% Change(a)"],["Mid-Atlantic","$","5,164","","","$","4,584","","","$","580","","","12.7","%"],["Midwest","4,650","","","4,060","","","590","","","14.5","%"],["New York","1,595","","","1,575","","","20","","","1.3","%"],["ERCOT","1,543","","","1,181","","","362","","","30.7","%"],["Other Power Regions","6,732","","","4,890","","","1,842","","","37.7","%"],["Total electric revenues","19,684","","","16,290","","","3,394","","","20.8","%"],["Other","5,944","","","3,992","","","1,952","","","48.9","%"],["Mark-to-market losses","(1,188)","","","(633)","","","(555)"],["Total Operating revenues","$","24,440","","","$","19,649","","","$","4,791","","","24.4","%"]]
[[/GREPCENT_TABLE]]
__________

(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:

[[GREPCENT_TABLE]]
[["","","","","","2022 vs. 2021"],["Supply Source (GWhs)","2022","","2021","","Variance","","% Change"],["Nuclear Generation(a)"],["Mid-Atlantic","53,214","","","53,589","","","(375)","","","(0.7)","%"],["Midwest","95,090","","","93,107","","","1,983","","","2.1","%"],["New York(b)","25,046","","","26,294","","","(1,248)","","","(4.7)","%"],["Total Nuclear Generation","173,350","","","172,990","","","360","","","0.2","%"],["Natural Gas, Oil and Renewables"],["Mid-Atlantic","2,097","","","2,271","","","(174)","","","(7.7)","%"],["Midwest","1,202","","","1,083","","","119","","","11.0","%"],["New York","\u2014","","","1","","","(1)","","","(100.0)","%"],["ERCOT","14,124","","","13,187","","","937","","","7.1","%"],["Other Power Regions","10,189","","","9,995","","","194","","","1.9","%"],["Total Natural Gas, Oil and Renewables","27,612","","","26,537","","","1,075","","","4.1","%"],["Purchased Power"],["Mid-Atlantic","15,366","","","13,576","","","1,790","","","13.2","%"],["Midwest","610","","","561","","","49","","","8.7","%"],["ERCOT","3,575","","","3,256","","","319","","","9.8","%"],["Other Power Regions","51,131","","","50,212","","","919","","","1.8","%"],["Total Purchased Power","70,682","","","67,605","","","3,077","","","4.6","%"],["Total Supply/Sales by Region"],["Mid-Atlantic","70,677","","","69,436","","","1,241","","","1.8","%"],["Midwest","96,902","","","94,751","","","2,151","","","2.3","%"],["New York(b)","25,046","","","26,295","","","(1,249)","","","(4.7)","%"],["ERCOT","17,699","","","16,443","","","1,256","","","7.6","%"],["Other Power Regions","61,320","","","60,207","","","1,113","","","1.8","%"],["Total Supply/Sales by Region","271,644","","","267,132","","","4,512","","","1.7","%"]]
[[/GREPCENT_TABLE]]

__________

(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 the Combined Notes to Consolidated Financial Statements 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.

[[GREPCENT_TABLE]]
[["","2022","","2021"],["Nuclear fleet capacity factor","94.8","%","","94.5","%"],["Refueling outage days","212","","","262"],["Non-refueling outage days","54","","","34"]]
[[/GREPCENT_TABLE]]

62

Table of Contents

ZEC Prices. We are compensated through state programs for the carbon-free attributes of our nuclear generation. ZEC programs are a significant contributor to our total operating revenues. The following table includes the average ZEC reference prices ($/MWh) for each of our major regions in which state programs have been enacted. Prices reflect the weighted average price for the various delivery periods within the years ended December 31, 2022 and 2021.

[[GREPCENT_TABLE]]
[["","","","","","2022 vs. 2021"],["State (Region)(a)","2022","","2021","","Variance","","% Change"],["New Jersey (Mid-Atlantic)","$","10.00","","","$","10.00","","","$","\u2014","","","\u2014","%"],["Illinois (Midwest)","13.88","","","16.50","","","(2.62)","","","(15.9)","%"],["New York (New York)","21.38","","","20.93","","","0.45","","","2.2","%"]]
[[/GREPCENT_TABLE]]

__________

(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 period June 1, 2022 through May 31, 2023). If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. For the year ended December 31, 2022 the average CMC price per MWh was a net negative value ($42.20). See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Illinois CMC program.

Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a significant impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. 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 the years ended December 31, 2022 and 2021.

[[GREPCENT_TABLE]]
[["","","","","","2022 vs. 2021"],["Location (Region)","2022","","2021","","Variance","","% Change"],["Eastern Mid-Atlantic Area Council (Mid-Atlantic and Midwest)","$","126.14","","","$","174.96","","","$","(48.82)","","","(27.9)","%"],["ComEd (Midwest)","121.71","","","192.45","","","(70.74)","","","(36.8)","%"],["Rest of State (New York)","85.36","","","98.35","","","(12.99)","","","(13.2)","%"],["Southeast New England (Other)","138.21","","","163.66","","","(25.45)","","","(15.6)","%"]]
[[/GREPCENT_TABLE]]

Electricity Prices. As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost. We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense within each region, depending on our net hourly position. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the region, weather, on-going competition, emerging technologies, as well as macroeconomic and regulatory factors.The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for each of our major regions and does not necessarily reflect prices we ultimately realized.

63

Table of Contents

[[GREPCENT_TABLE]]
[["","","","","","2022 vs. 2021"],["Location (Region)","2022","","2021","","Variance","","% Change"],["PJM West (Mid-Atlantic)","$","72.90","","","$","38.91","","","$","33.99","","","87.4","%"],["ComEd (Midwest)","60.24","","","34.76","","","25.48","","","73.3","%"],["Central (New York)","57.52","","","29.90","","","27.62","","","92.4","%"],["North (ERCOT)","64.38","","","146.63","","","(82.25)","","","(56.1)","%"],["Southeast Massachusetts (Other)(a)","86.02","","","46.38","","","39.64","","","85.5","%"]]
[[/GREPCENT_TABLE]]

__________

(a)Reflects New England, which comprises the majority of the activity in the Other region.

For the year ended December 31, 2022 compared to 2021, changes in Operating revenues by region were approximately as follows:

[[GREPCENT_TABLE]]
[["","2022 vs. 2021"],["","Variance","","% Change(a)","","Description"],["Mid-Atlantic","$","580","","","12.7","%","","\u2022 favorable retail load revenue of $525 primarily due to higher energy prices \u2022 favorable wholesale load revenue of $360 primarily due to higher volumes and energy prices; partially offset by \u2022 unfavorable settled economic hedges of ($280) due to settled prices relative to hedged prices"],["Midwest","590","","","14.5","%","","\u2022 favorable net wholesale load and generation revenue of $630 primarily due to higher nuclear generation and energy prices, partially offset by CMC program activity and the absence of net capacity revenue \u2022 favorable retail load revenue of $275 primarily due to higher energy prices \u2022 favorable PJM performance bonuses of $116 due to generation performance against capacity requirements during December 2022 weather event; partially offset by \u2022 unfavorable settled economic hedges of ($430) due to settled prices relative to hedged prices"],["New York","20","","","1.3","%","","\u2022 favorable retail load revenue of $295 primarily due to higher energy prices \u2022 favorable generation revenue of $150 due to higher energy prices, partially offset by lower nuclear generation due to an increase in outage days; partially offset by \u2022 unfavorable settled economic hedges of ($410) due to settled prices relative to hedged prices"],["ERCOT","362","","","30.7","%","","\u2022 favorable settled economic hedges of $340 due to settled prices relative to hedged prices \u2022 favorable retail load revenue of $115 primarily due to higher volumes partially offset by lower energy prices relative to the prior year due to the February 2021 extreme cold weather event; partially offset by \u2022 unfavorable 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"],["Other Power Regions","1,842","","","37.7","%","","\u2022 favorable wholesale load revenue of $820 due to higher energy prices and volumes \u2022 favorable settled economic hedges of $540 due to settled prices relative to hedged prices \u2022 favorable retail load revenue of $430 due to higher energy prices and volumes"]]
[[/GREPCENT_TABLE]]

64

Table of Contents

[[GREPCENT_TABLE]]
[["Other","1,952","","","48.9","%","","\u2022 favorable gas revenue, including settled financial hedges, of $1,655 primarily due to higher gas prices \u2022 favorable energy revenue of $370 primarily due to higher energy prices; partially offset by \u2022 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 ($70)"],["Mark-to-market(b)","(555)","","","","","\u2022 losses on economic hedging activities of ($1,188) in 2022 compared to losses of ($633) in 2021"],["Total","$","4,791","","","24.4","%"]]
[[/GREPCENT_TABLE]]

__________

(a)% Change in mark-to-market is not a meaningful measure.

(b)See Note 16 — 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: wholesale and retail sales of 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 year ended December 31, 2022 compared to 2021, Purchased power and fuel expense by region were as follows:

[[GREPCENT_TABLE]]
[["","","","","","2022 vs. 2021"],["","2022","","2021","","Variance","","% Change(a)"],["Mid-Atlantic","$","3,026","","","$","2,320","","","$","(706)","","","(30.4)","%"],["Midwest","1,886","","","1,343","","","(543)","","","(40.4)","%"],["New York","528","","","414","","","(114)","","","(27.5)","%"],["ERCOT","1,136","","","2,006","","","870","","","43.4","%"],["Other Power Regions","5,811","","","3,999","","","(1,812)","","","(45.3)","%"],["Total electric purchased power and fuel","12,387","","","10,082","","","(2,305)","","","(22.9)","%"],["Other","5,250","","","3,279","","","(1,971)","","","(60.1)","%"],["Mark-to-market gains","(175)","","","(1,198)","","","(1,023)"],["Total purchased power and fuel","$","17,462","","","$","12,163","","","$","(5,299)","","","(43.6)","%"]]
[[/GREPCENT_TABLE]]

__________

(a)% Change in mark-to-market is not a meaningful measure.

65

Table of Contents

For the year ended December 31, 2022 compared to 2021, changes in Purchased power and fuel expense by region were approximately as follows:

[[GREPCENT_TABLE]]
[["","2022 vs. 2021"],["","Variance","","% Change(a)","","Description"],["Mid-Atlantic","$","(706)","","","(30.4)","%","","\u2022 unfavorable purchased power and net capacity impact of ($660) primarily due to higher energy prices, higher load, and lower capacity prices earned \u2022 unfavorable PJM net non-performance charges of ($7) due to generation performance against capacity requirements during December 2022 weather event"],["Midwest","(543)","","","(40.4)","%","","\u2022 unfavorable purchased power and net capacity impact of ($590) primarily due to higher energy prices, lower capacity prices earned, and lower cleared capacity volumes; partially offset by \u2022 favorable nuclear fuel cost of $65 primarily due to the absence of accelerated amortization of nuclear fuel and lower nuclear fuel prices in the prior year"],["New York","(114)","","","(27.5)","%","","\u2022 unfavorable purchased power and net capacity impact of ($190) primarily due to higher energy prices, lower nuclear generation and lower capacity prices earned; partially offset by \u2022 favorable settlement of economic hedges of $90 due to settled prices relative to hedged prices"],["ERCOT","870","","","43.4","%","","\u2022 favorable purchased power of $635 primarily due to lower energy prices relative to the prior year due to the February 2021 extreme cold weather event \u2022 favorable settlement of economic hedges of $140 due to settled prices relative to hedged prices \u2022 favorable fuel cost of $80 primarily due to lower gas prices relative to the prior year due to the February 2021 extreme cold weather event"],["Other Power Regions","(1,812)","","","(45.3)","%","","\u2022 unfavorable purchased power and net capacity impact of ($2,180) primarily due to higher energy prices, higher load, lower cleared capacity volumes and lower capacity prices earned \u2022 unfavorable fuel cost of ($400) primarily due to higher gas prices \u2022 unfavorable environmental products activity of ($415) primarily driven by lower optimization and higher RPS costs; partially offset by \u2022 favorable settlement of economic hedges of $1,210 due to settled prices relative to hedged prices"],["Other","(1,971)","","","(60.1)","%","","\u2022 unfavorable net gas purchase costs and settlement of economic hedges of ($1,885) \u2022 unfavorable energy purchases of ($290) primarily due to higher energy prices \u2022 unfavorable fair value adjustment related to gas imbalances of ($50); partially offset by \u2022 favorable impact due to the absence of LDC and pipeline penalties due to the February 2021 extreme cold weather event of $110 \u2022 favorable impact due to the absence of accelerated nuclear fuel amortization associated with announced early plant retirements of $150"]]
[[/GREPCENT_TABLE]]

66

Table of Contents

[[GREPCENT_TABLE]]
[["Mark-to-market(b)","(1,023)","","","","","\u2022 gains on economic hedging activities of $175 in 2022 compared to gains of $1,198 in 2021"],["Total","$","(5,299)","","","(43.6)","%"]]
[[/GREPCENT_TABLE]]
__________

(a)% Change in mark-to-market is not a meaningful measure.

(b)See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.

The changes in Operating and maintenance expense consisted of the following:

[[GREPCENT_TABLE]]
[["","2022 vs. 2021"],["","Increase (Decrease)"],["Labor, other benefits, contracting, and materials(a)","$","317"],["Decommissioning-related activities(b)","298"],["NEIL insurance distributions","83"],["Plant retirements and divestitures(c)","78"],["Separation costs(d)","74"],["Loss on sale of receivables","33"],["Nuclear refueling outage costs, including the co-owned Salem plants","32"],["Credit loss expense(e)","(23)"],["Covid-19 direct costs","(35)"],["Prior merger commitment(f)","(50)"],["Asset impairments","(541)"],["Other","20"],["Total increase","$","286"]]
[[/GREPCENT_TABLE]]

__________

(a)Primarily reflects increased employee-related costs, including labor, stock-based compensation, and other incentives, etc.

(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 the Combined Notes to Consolidated Financial Statements for additional information.

(c)Reflects the absence of the reversal of charges recorded in 2021 associated with the reversal of the previous decision to early retire Byron and Dresden.

(d)Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA.

(e)Primarily a result of the February 2021 extreme cold weather event.

(f)Reversal of a charge related to a prior merger commitment.

Depreciation and amortization expense decreased for the year ended December 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 year ended December 31, 2022 compared to the same period in 2021, primarily due to gains on sales of equity investments and a gain on sale of our solar business which were recognized in 2021.

Interest expense, net decreased for the year ended December 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 and the retirement of long-term debt in March 2022. See Note 17 — Debt and Credit Agreements 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 year ended December 31, 2022 compared to the same period in 2021, due to activity described in the table below:

67

Table of Contents

[[GREPCENT_TABLE]]
[["","2022","","2021"],["Net unrealized (losses) gains on NDT funds(a)","$","(798)","","","$","204"],["Net realized gains on sale of NDT funds(a)","4","","","381"],["Interest and dividend income on NDT funds(a)","93","","","98"],["Contractual elimination of income tax (expense) benefit(b)","(201)","","","226"],["Non-service net periodic benefit credit(c)","110","","","\u2014"],["Net realized and unrealized losses from equity investments(d)","(13)","","","(160)"],["Return to provision adjustment(e)","(49)","","","\u2014"],["TSA billings(f)","44","","","\u2014"],["Other","24","","","46"],["Total Other, net","$","(786)","","","$","795"]]
[[/GREPCENT_TABLE]]

_________ 

(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) benefit 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 (cost) from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.

(d)For 2022, includes net realized and unrealized (losses) gains from equity investments. For 2021, includes net unrealized (losses) gains from equity investments.

(e)Reflects amounts contractually owed to Exelon under the TMA, which is offset in Income taxes. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

(f)Amounts we billed Exelon for services pursuant to the TSA. See Note 1 - Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information.

Effective income tax rates were 71.6% and 148% for the years ended December 31, 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 and one-time income tax adjustments. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Net (loss) income attributable to noncontrolling interests primarily relates to CRP for the year ended December 31, 2022 and includes CENG and CRP for the same period in 2021. The decrease for the year ended December 31, 2022 for 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 the Combined Notes to Consolidated Financial Statements for additional information.

Liquidity and Capital Resources

For discussion of the year ended December 31, 2021 compared to the year ended December 31, 2020, refer to Liquidity and Capital Resources of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2021 Form 10-K which was filed with the SEC on February 25, 2022.

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

68

Table of Contents

deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $5.8 billion. We utilize our credit facilities to support our commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 17 — 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 10 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

If a nuclear plant were to retire before the end of its licensed life, there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that we address the shortfall by providing additional financial assurances, such as surety bonds, letters of credit, or parent company guarantees for our share of the funding assurance. However, the amount of any assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. No later than two years after shutting down a plant, we must submit a PSDAR to the NRC that includes the planned option for decommissioning the site.

Upon issuance of any additional financial assurance mechanisms to address a decommissioning funding shortfall, subject to satisfying various regulatory preconditions, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an exemption in order for us to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs, if applicable). Any amounts not covered by an exemption would be borne by us without reimbursement.

As of December 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 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. On June 8, 2022, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for site restoration costs.

Cash Flows from Operating Activities

Our cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Our future cash flows from operating activities may be affected by future demand for, and market prices of, energy and our ability to continue to produce and supply power at competitive costs, as well as to obtain collections from customers and the sale of certain receivables.

See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

69

Table of Contents

The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2022 and 2021:

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["(Decrease) increase in cash flows from operating activities","2022","","2021","","Change"],["Net loss","$","(167)","","","$","(83)","","","$","(84)"],["Adjustments to reconcile net loss to cash:"],["Changes in working capital and other noncurrent assets and liabilities(a)","(5,246)","","","(3,608)","","","(1,638)"],["Collateral posted, net","(351)","","","(130)","","","(221)"],["Pension and non-pension postretirement benefit contributions","(237)","","","(259)","","","22"],["Option premiums paid, net","(177)","","","(338)","","","161"],["Total non-cash operating activities(b)","3,825","","","3,080","","","745"],["Decrease in cash flows from operating activities","$","(2,353)","","","$","(1,338)","","","$","(1,015)"]]
[[/GREPCENT_TABLE]]
__________

(a)Includes changes in Accounts receivable, Receivables from and payables to affiliates, Inventories, Accounts payable and accrued expenses, Income taxes, and Other assets and liabilities.

(b)See the Consolidated Statements of Cash Flows for details of non-cash operating activities, includes Depreciation, amortization, and accretion, Asset impairments, Gain on sales of assets and businesses, Deferred income taxes and amortization of ITCs, Net fair value changes related to derivatives, and Net realized and unrealized activity associated with NDTs and equity investments. See Note 23 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information on the Other non-cash operating activities line.

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 2022 and 2021 were as follows:

•A reduction in cash inflows for changes in working capital and other noncurrent assets and liabilities primarily driven by activity related to the accounts receivable Facility, due to higher retail power sales and associated accounts receivables sold relative to the maximum funding limit of the Facility, partially offset by an increase in cash inflows from the Collection of DPP, net in Cash Flows from investing activities, which can be seen in the Cash Flows from Investing Activities section below. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivables.

•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 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral.

•Option premiums paid, net 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. Note 16 — Derivative Financial Instruments of the Notes to Consolidated Financial Statements for additional information on derivative contracts.

70

Table of Contents

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2022 and 2021:

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["(Decrease) increase in cash flows from investing activities","2022","","2021","","Change"],["Proceeds from sales of assets and businesses","$","52","","","$","878","","","$","(826)"],["Capital expenditures","(1,689)","","","(1,329)","","","(360)"],["Investment in NDT funds, net","(221)","","","(141)","","","(80)"],["Collection of DPP, net","4,964","","","3,902","","","1,062"],["Other investing activities","(2)","","","(28)","","","26"],["Decrease in cash flows from investing activities","$","3,104","","","$","3,282","","","$","(178)"]]
[[/GREPCENT_TABLE]]

Significant investing cash flow impacts for 2022 and 2021 were as follows:

•Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of our solar business, sale of a biomass facility and proceeds received on sales of equity investments in 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the sale of our solar business and biomass facility.

•Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending.

•Collection of DPP, net increased due to cash collections from the accounts receivable Facility, as discussed in the Cash Flows from Operating Activities section above. This was partially offset by a reduction in cash proceeds received from the Purchasers in 2022 compared to 2021. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2022 and 2021:

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["Increase (decrease) in cash flows from financing activities","2022","","2021","","Change"],["Distributions to Exelon","$","\u2014","","","$","(1,832)","","","$","1,832"],["Contributions from Exelon","1,750","","","64","","","1,686"],["Acquisition of CENG noncontrolling interest","\u2014","","","(885)","","","885"],["Change in money pool with Exelon","\u2014","","","(285)","","","285"],["Dividends paid on common stock","(185)","","","\u2014","","","(185)"],["Long-term debt, net","(1,406)","","","47","","","(1,453)"],["Changes in short-term borrowings, net","(923)","","","1,242","","","(2,165)"],["Other financing activities","(35)","","","(46)","","","11"],["Increase in cash flows from financing activities","$","(799)","","","$","(1,695)","","","$","896"]]
[[/GREPCENT_TABLE]]

Significant financing cash flow impacts for 2022 and 2021 were as follows:

•Distributions to Exelon is related to distributions made prior to separation. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation.

71

Table of Contents

•Contributions from Exelon is primarily 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.

•See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the acquisition of CENG noncontrolling interest.

•Change 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.

•Refer to ITEM 5. — MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES for additional information on dividend restrictions. See below for quarterly dividends declared.

•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for additional information.

•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.

Debt Issuances and Redemptions

See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our long-term debt. Debt activity for 2022 and 2021 was as follows:

During 2022, the following long-term debt was issued:

[[GREPCENT_TABLE]]
[["Type","","Interest Rate","","Maturity","","Amount","","Use of Proceeds"],["Energy Efficiency Project Financing(a)","","2.20% - 6.96%","","March 31, 2023 - May 1, 2024","","$","14","","","Funding to install energy conservation measures."]]
[[/GREPCENT_TABLE]]

__________

(a)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

During 2021, the following long-term debt was issued:

[[GREPCENT_TABLE]]
[["Type","","Interest Rate","","Maturity","","Amount","","Use of Proceeds"],["West Medway II Nonrecourse Debt(a)","","1 month LIBOR + 3%(b)","","March 31, 2026","","$","150","","","Funding for general corporate purposes."],["Energy Efficiency Project Financing(c)","","2.53% - 4.24%","","January 31, 2022 - February 28, 2022","","2","","Funding to install energy conservation measures."]]
[[/GREPCENT_TABLE]]
__________

(a)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.

(b)The nonrecourse debt has an average blended interest rate.

(c)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

72

Table of Contents

During 2022, the following long-term debt was retired and/or redeemed:

[[GREPCENT_TABLE]]
[["Type","","Interest Rate","","Maturity","","Amount"],["Senior Notes","","3.40%","","March 15, 2022","","$","500"],["Senior Notes","","4.25%","","June 15, 2022","","523"],["CR Nonrecourse Debt(a)","","3 month LIBOR + 2.50%","","December 15, 2027","","41"],["Continental Wind Nonrecourse Debt(a)","","6.00%","","February 28, 2033","","37"],["West Medway II Nonrecourse Debt(a)","","1 month LIBOR + 2.875%(c)","","March 31, 2026","","24"],["Antelope Valley DOE Nonrecourse Debt(a)(b)","","2.29% - 3.56%","","January 5, 2037","","25"],["RPG Nonrecourse Debt(a)","","4.11%","","March 31, 2035","","9"],["Energy Efficiency Project Financing","","3.71%","","December 31, 2022","","3"]]
[[/GREPCENT_TABLE]]

__________

(a)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.

(b)On January 6, 2023, we redeemed $5 million of 2.29% - 3.56% Antelope Valley DOE nonrecourse debt.

(c)The nonrecourse debt has an average blended interest rate.

During 2021, the following long-term debt was retired and/or redeemed:

[[GREPCENT_TABLE]]
[["Type(a)","","Interest Rate","","Maturity","","Amount"],["Continental Wind Nonrecourse Debt(b)","","6.00%","","February 28, 2033","","$","35"],["CR Nonrecourse Debt(b)","","3-month LIBOR + 2.50%(c)","","December 15, 2027","","17"],["SolGen Nonrecourse Debt(b)","","3.93%","","September 30, 2036","","7"],["Antelope Valley DOE Nonrecourse Debt(b)(d)","","2.29% - 3.56%","","January 5, 2037","","24"],["West Medway II Nonrecourse Debt(b)","","LIBOR + 3%(e)","","March 31, 2026","","13"],["RPG Nonrecourse Debt(b)","","4.11%","","March 31, 2035","","9"]]
[[/GREPCENT_TABLE]]

__________

(a)As part of the 2012 merger, Exelon entered intercompany loan agreements that mirrored the terms and amounts of third-party debt obligations. In connection with the separation, on January 31, 2022, we paid cash to Exelon Corporate of $258 million to settle the intercompany loan. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt.

(b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.

(c)The interest rate was amended to 3-month LIBOR + 2.50% on June 16, 2021.

(d)On January 5, 2022, we redeemed $6 million of 2.29% - 3.56% Antelope Valley DOE nonrecourse debt.

(e)The nonrecourse debt has an average blended interest rate.

From time to time and as market conditions warrant, we may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt.

Dividends

Quarterly dividends declared by our Board of Directors during the twelve months ended December 31, 2022 and for the first quarter of 2023 were as follows:

[[GREPCENT_TABLE]]
[["Period","","Declaration Date","","Shareholder of Record Date","","Dividend Payable Date","","Cash per Share"],["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"],["Third Quarter of 2022","","July 26, 2022","","August 15, 2022","","September 9, 2022","","$","0.1410"],["Fourth Quarter of 2022","","October 31, 2022","","November 15, 2022","","December 9, 2022","","$","0.1410"],["First Quarter of 2023","","February 15, 2023","","February 27, 2023","","March 10, 2023","","$","0.2820"]]
[[/GREPCENT_TABLE]]

73

Table of Contents

Credit Matters and Cash Requirements

We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of December 31, 2022, we have access to facilities with aggregate bank commitments of $5.8 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during 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 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 had lost our investment grade credit rating as of December 31, 2022, we would have been required to provide incremental collateral estimated to be approximately $3.3 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. A loss of investment grade credit rating would have required a significant reduction in credit ratings from their current levels of BBB and Baa2 at S&P and Moody's, respectively, to BB+ and Ba1 or below. As of December 31, 2022, we had $2.2 billion of available capacity and $0.4 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding our available capacity and cash on hand, we would be required to access additional liquidity through the capital markets. See Note 16 — Derivative Financial Instruments and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Capital Expenditures

Our most recent estimate of capital expenditures is approximately $2.6 billion for 2023 and approximately $5.0 billion for the period from 2024 to 2025. Approximately 45-47% of projected capital expenditures are for the acquisition of nuclear fuel, which includes additional nuclear fuel to increase inventory levels. This is a strategic decision in response to the potential for the continuing Russia and Ukraine conflict to impact our long-term nuclear fuel supply. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Other Key Business Drivers for more information on the Russia and Ukraine conflict.

Additionally, the above estimate of capital expenditures includes $1.5 billion of growth capital expenditures, including nuclear uprates, wind repowering, and hydrogen. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Executive Overview for additional information.

The remaining amounts primarily reflect additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages). 

Planned additions and upgrades and other investments are subject to periodic review and revision to reflect changes in economic conditions impacting our generating assets and other factors, including, but not limited to, market power prices, results of capacity auctions, potential legislative and regulatory solutions, impacts of inflation, changes in the cost of materials and labor, and financing costs.

We anticipate funding these capital expenditures with a combination of internally generated funds and borrowings.

74

Table of Contents

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, and management of the pension obligation. The Pension Protection 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 over time. This level funding strategy helps minimize volatility of future period required pension contributions. Unlike the qualified pension plans, our non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded certain of our plans. For our funded OPEB plans, we consider several factors in determining the level of contributions including liabilities management and levels of benefit claims paid.

The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2023 (including our benefit payments related to unfunded plans):

[[GREPCENT_TABLE]]
[["","Qualified Pension Plans","","Non-Qualified Pension Plans","","OPEB"],["Planned contributions","$","21","","","$","10","","","$","17"]]
[[/GREPCENT_TABLE]]

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 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.

Cash Requirements for Other Financial Commitments

The following table summarizes our future estimated cash payments as of December 31, 2022 under existing financial commitments:

[[GREPCENT_TABLE]]
[["","2023","","Beyond 2023","","Total","","Time Period"],["Long-term debt","$","143","","","$","4,507","","","$","4,650","","","2023 - 2042"],["Interest payments on long-term debt(a)","225","","","2,448","","","2,673","","","2023 - 2042"],["Operating leases(b)","54","","","502","","","556","","","2023 - 2066"],["Purchase power obligations(c)","825","","","964","","","1,789","","","2023 - 2033"],["Fuel purchase agreements(d)","1,288","","","6,457","","","7,745","","","2023 - 2036"],["Other purchase obligations(e)","1,289","","","1,815","","","3,104","","","2023 - 2046"],["SNF obligation","\u2014","","","1,230","","","1,230","","","2023 - 2035"],["Pension contributions(f)","21","","","183","","","204","","","2023 - 2028"],["Total cash requirements","$","3,845","","","$","18,106","","","$","21,951"]]
[[/GREPCENT_TABLE]]

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2022 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2022.

(b)Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $47 million and $322 million for 2023 and beyond 2023, respectively and $369 million in total.

75

Table of Contents

(c)Purchase power obligations primarily include expected payments for REC purchases and capacity payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature.

(d)Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services.

(e)Represents the future estimated value at December 31, 2022 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into with third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(f)These amounts represent our expected contributions to our qualified pension plans. Qualified pension contributions for years after 2028 are not included.

See Note 19 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of our other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the table above in the Combined Notes to Consolidated Financial Statements.

[[GREPCENT_TABLE]]
[["Item","","Location within Combined Notes to Consolidated Financial Statements"],["Long-term debt","","Note 17 \u2014 Debt and Credit Agreements"],["Interest payments on long-term debt","","Note 17 \u2014 Debt and Credit Agreements"],["Operating leases","","Note 11 \u2014 Leases"],["SNF obligation","","Note 19 \u2014 Commitments and Contingencies"],["Pension contributions","","Note 15 \u2014 Retirement Benefits"]]
[[/GREPCENT_TABLE]]

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 August 15, 2025 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 Combined Notes to Consolidated Financial Statements for additional information on project finance credit facilities 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 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities.

76

Table of Contents

Capital Structure

At December 31, 2022, our capital structure consisted of the following:

[[GREPCENT_TABLE]]
[["","Percentage of Capital Structure"],["Commercial paper and notes payable","7","%"],["Long-term debt","27","%"],["Member\u2019s equity","66","%"]]
[[/GREPCENT_TABLE]]

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 credit 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 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

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, 2022. We have only engaged S&P and Moody's for ratings coverage following separation. On October 13, 2022, S&P raised our senior unsecured debt rating to 'BBB' from 'BBB-' citing the passage of the IRA as a material credit positive for us.