Constellation Energy Corp 10-K

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 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. COVID-19. We have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. We provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus by taking extra precautions for employees who work in the field and in our facilities. We have implemented work from home policies where appropriate, and imposed travel limitations on employees. We continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers. There were no changes in internal control over financial reporting as a result of COVID-19 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information. Unfavorable economic conditions due to COVID-19 resulted in an estimated reduction to our Net income of approximately $170 million for the year ended December 31, 2020. The impact was not material for the year ended December 31, 2021. We assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 or 2021 as a result of COVID-19. See Note 12 — Asset Impairments of the Notes to Consolidated Financial Statements for additional information related to other impairment assessments. We will continue to monitor developments affecting our workforce, customers, and suppliers and will take additional precautions that we determine to be necessary in order to mitigate the impacts. We cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, the rate, and public perceptions of the effectiveness, of vaccinations and rate of resumption of business activity. Significant 2021 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 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 24 — Separation from Exelon of the Notes to Consolidated Financial Statements for additional information. In connection with the separation, we incurred transaction costs of $49 million for the year ended December 31, 2021, which are recorded in Operating and maintenance expense. We expect to incur incremental transaction costs of approximately $150 million and $60 million in 2022 and 2023, respectively. The transaction costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation. 48 Table of Contents CENG Put Option EDF had the option to sell its 49.99% equity interest in CENG to us exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, we received notice of EDF’s intention to exercise the put option and sell its 49.99% equity interest in CENG to us and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. On August 6, 2021, we entered into a settlement agreement with EDF pursuant to which we, through a wholly owned subsidiary, purchased EDF’s equity interest in CENG for a net purchase price of $885 million, which includes, among other things, a credit for EDF’s share of the balance of the preferred distribution payable by CENG to us. The difference between the net purchase price and EDF’s noncontrolling interest as of the closing date was recorded to Membership Interest in the Consolidated Balance Sheet. In connection with the settlement agreement, on August 6, 2021, we issued approximately $880 million under a term loan credit agreement to fund the transaction, which will expire on August 5, 2022. See Note 2 – Mergers, Acquisitions, and Dispositions and Note 17 — Debt and Credit Agreements of the Notes to Consolidated Financial Statements for additional information. Clean Energy Law On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law is designed to achieve 100% carbon-free power by 2045 to enable the state’s transition to a clean energy economy. The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorized the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. The Byron, Dresden, and Braidwood nuclear plants located in Illinois participated in the CMC procurement process and were awarded contracts that commit each plant to operate through May 31, 2027. Pursuant to these contracts, ComEd will procure CMCs based upon the number of MWhs produced annually by each plant, subject to minimum performance requirements. See Note 3 — Regulatory Matters of the Notes to Consolidated Financial Statements for additional information. Following enactment of the Clean Energy Law, we announced on September 15, 2021 that we reversed our previous decision to retire Byron and Dresden given the opportunity for additional revenue. In addition, we no longer consider the Braidwood or LaSalle nuclear plants to be at risk for premature retirement. See Note 7 - Early Plant Retirements of the Notes to Consolidated Financial Statements for additional information and Early Retirement of Generation Facilities below. Early Retirement of Generation Facilities In August 2020, we announced the intention to retire the Byron Generating Station in September 2021, Dresden Generating Station in November 2021, and Mystic Units 8 and 9 at the expiration of the cost of service commitment in May 2024. As a result, we recognized a $500 million pre-tax impairment for the New England asset group along with certain one-time charges in the third and fourth quarters of 2020, in addition to ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel. In the second quarter of 2021, an incremental decline in value resulted in an additional pre-tax impairment charge of $350 million for the New England asset group. 49 Table of Contents We recorded pre-tax charges of $53 million and $140 million in the second and third quarters of 2021, respectively, for decommissioning-related activities that were not offset for the Byron units due to the inability to recognize a regulatory asset at ComEd. On September 15, 2021, we reversed our previous decision to early retire Byron and Dresden and the expected economic useful life for both facilities was updated to 2044 and 2046 for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. In addition, in the third quarter of 2021, we reversed approximately $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in the third and fourth quarters of 2020 associated with the early retirements. We recognized pre-tax expenses for Byron, Dresden, and Mystic Units 8 and 9 of $1,458 million for the year ended December 31, 2021, primarily due to accelerated depreciation and amortization of plant assets, partially offset by the reversal of one-time charges for Byron and Dresden. See Note 7 — Early Plant Retirements, Note 10 — Asset Retirement Obligations, and Note 12 — Asset Impairments of the Notes to Consolidated Financial Statement for additional information. Impacts of February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. The estimated impact to our Net income for the year ended December 31, 2021 arising from these market and weather conditions was a reduction of approximately $800 million. The ultimate impact to our consolidated financial statements may be affected by a number of factors, including the impacts of customer and counterparty defaults and recoveries, any additional solutions to address the financial challenges caused by the event, and related litigation and contract disputes. See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Notes to Consolidated Financial Statements for additional information. To offset a portion of the unfavorable impacts, we identified between $370 million and $450 million of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings, which was achieved in 2021. Agreement for the Sale of a Biomass Facility On April 28, 2021, we entered into a purchase agreement with ReGenerate Energy Holdings, LLC ("ReGenerate"), under which ReGenerate agreed to purchase our interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, we recorded a pre-tax impairment charge of $140 million. The sale was completed on June 30, 2021 for a net purchase price of $36 million. See Note 2 — Mergers, Acquisitions, and Dispositions of the Notes to Consolidated Financial Statements for additional information. Agreement for Sale of Our Solar Business On December 8, 2020, we entered into an agreement for the sale of a significant portion of our solar business, including 360 megawatts of generation in operation or under construction at more than 600 sites across the United States. Completion of the sale occurred on March 31, 2021 for a purchase price of $810 million. See Note 2 — Mergers, Acquisitions, and Dispositions of the Notes to Consolidated Financial Statements for additional information. 50 Table of Contents Other Key Business Drivers Power Markets Section 232 Uranium Petition On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce ("DOC") seeking relief under Section 232 of the Trade Expansion Act of 1962 from imports of uranium products, alleging that these imports threaten national security. The United States Nuclear Fuel Working Group ("Working Group") report was made public on April 23, 2020. The Working Group report states that nuclear power is intrinsically tied to national security, and promises that the U.S. government will take bold actions to strengthen all parts of the nuclear fuel industry in the U.S. It recommends the Agreement Suspending the Antidumping Investigation on Uranium from the Russian Federation (the “Russian Suspension Agreement” or "RSA") be extended and to consider reducing the amount of Russian imports of nuclear fuel. The Russian Suspension Agreement is the historical resolution of a 1991 DOC investigation that found that the Russians had been selling or “dumping” cheap uranium products into the U.S. The RSA has been amended several times in the intervening years to allow Russia to supply limited amounts of uranium products into the U.S. It was set to expire at the end of 2020, but was amended on October 5, 2020 to extend for another 20 years. The Working Group report should be viewed as policy recommendations that may be implemented by executive agencies, congress, and or regulatory bodies. We cannot predict the outcome of all of the policy changes recommended by the Working Group. Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps On February 21, 2019, PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM argued that this allows for the exercise of market power. The IMM asked FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. Several consumer advocates filed a complaint seeking similar relief several months after the IMM’s complaint. On March 18, 2021, FERC granted the complaints, finding the current estimate of performance assessment intervals to be excessive compared to the reasonably expected number of performance assessment intervals which results in an unjust and unreasonable default offer cap. FERC did not establish the number of performance assessment intervals that should be used to calculate the default offer cap and instead requested briefs on the matter, including alternative approaches to mitigation in the capacity market. We submitted initial and reply briefs on May 3, 2021 and June 9, 2021, respectively, and an answer to briefs filed by other parties on June 24, 2021. On September 2, 2021, FERC issued an order adopting the IMM's unit-specific avoidable cost offer review methodology and directed PJM to submit a compliance filing establishing new deadlines for offer review and related other activities leading up to the base residual auction for the 2023-2024 planning year and an additional compliance filing revising the PJM Tariff to comply with FERC's order. We filed at FERC for rehearing on this matter on October 4, 2021 which was deemed denied on November 4, 2021. A number of parties, including us, have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of these proceedings or the financial statement impact. Hedging Strategy We are exposed to commodity price risk associated with the unhedged portion of our electricity portfolio. We enter into non-derivative and derivative contracts, including options, swaps, and forward and futures contracts, all with credit-approved counterparties, to hedge this anticipated exposure. For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis. We may also enter into transactions that are outside of this ratable hedging program. As of December 31, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 92%-95% and 73%-76% for 2022 and 2023, 51 Table of Contents respectively. We have been and will continue to be proactive in using hedging strategies to mitigate commodity price risk. We procure natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 50% of our uranium concentrate requirements from 2022 through 2026 are supplied by three suppliers. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments have the potential to impact delivery from multiple suppliers in the international uranium 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 Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. 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 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 Notes to Consolidated Financial Statements. Nuclear Decommissioning Asset Retirement Obligations The AROs associated with decommissioning our nuclear un its were $12.7 billion at December 31, 2021. 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. 52 Table of Contents 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. The actual decommissioning approach selected once a nuclear facility is shutdown 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 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 increase from approximately $12.7 billion to approximately $16.0 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: Change in the CARFR applied to the annual ARO update (Decrease) Increase to ARO as of December 31, 2021 2020 CARFR rather than the 2021 CARFR $ (490) 2021 CARFR increased by 50 basis points (600) 2021 CARFR decreased by 50 basis points 750 53 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: Change in ARO Assumption Increase to ARO as of December 31, 2021 Cost escalation studies Uniform increase in escalation rates of 50 basis points $ 2,900 Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 10 percent 1,110 Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent (a) 480 Shorten each unit's probability weighted operating life assumption by 10 percent (b) 1,570 Extend the estimated date for DOE acceptance of SNF to 2040 290 __________ (a) Excludes any sites in which management has committed to a specific decommissioning approach. (b) Excludes any retired sites. See Note 1 — Significant Accounting Policies and Note 10 — Asset Retirement Obligations of the 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 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 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). 54 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 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 Notes to the 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 — Significant Accounting Policies of the 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 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. 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 55 Table of Contents 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 the NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed. 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. 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 energy, 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 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 Notes to Consolidated Financial Statements for additional information regarding derivative instruments. 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. 56 Table of Contents 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 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 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 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. 57 Table of Contents 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 — Significant Accounting Policies of the 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. Results of Operations For discussion of the year ended December 31, 2020 compared to the year ended December 31, 2019, refer to MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the Form 10. 2021 2020 Favorable (Unfavorable) Variance Operating revenues $ 19,649 $ 17,603 $ 2,046 Operating expenses Purchased power and fuel 12,163 9,585 (2,578) Operating and maintenance 4,555 5,168 613 Depreciation and amortization 3,003 2,123 (880) Taxes other than income taxes 475 482 7 Total operating expenses 20,196 17,358 (2,838) Gain on sales of assets and businesses 201 11 190 Operating (loss) income (346) 256 (602) Other income and (deductions) Interest expense, net (297) (357) 60 Other, net 795 937 (142) Total other income and (deductions) 498 580 (82) Income before income taxes 152 836 (684) Income taxes 225 249 24 Equity in losses of unconsolidated affiliates (10) (8) (2) Net (loss) income (83) 579 (662) Net income (loss) attributable to noncontrolling interests 122 (10) 132 Net (loss) income attributable to membership interest $ (205) $ 589 $ (794) Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income attributable to membership inte res t decreased by $794 million primarily due to: • Impacts of the February 2021 extreme cold weather event; • 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 58 Table of Contents on September 15, 2021, and our decision in the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024; • Decommissioning-related activities that were not offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date; • Impairments of the New England asset group, the Albany Green Energy biomass facility, and a wind project, partially offset by the absence of an impairment of the New England asset group in the third quarter of 2020; • Higher net unrealized and realized losses on equity investments; and • The absence of prior year one-time tax settlements. The decreases were partially offset by: • Higher mark-to-market gains; • Higher net unrealized and realized gains on NDT funds; • Absence of one time charges recorded in 2020 associated with our decision to early retire the Byron and Dresden nuclear facilities and Mystic Units 8 and 9, and the reversal of one-time charges resulting from the reversal of the previous decision to early retire Byron and Dresden on September 15, 2021; • Favorable sales and hedges of excess emission credits; • Favorable commodity prices on fuel hedges; • Lower nuclear fuel costs due to accelerated amortization of nuclear fuel and lower prices; and • Higher New York ZEC revenues due to higher generation and an increase in ZEC prices. 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 Notes to Consolidated Financial Statements for additional information on these reportable segments. 59 Table of Contents The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. For the year ended December 31, 2021 compared to 2020, Operating revenues by region were as follows: 2021 vs. 2020 2021 2020 Variance % Change (a) Mid-Atlantic $ 4,584 $ 4,645 $ (61) (1.3) % Midwest 4,060 4,024 36 0.9 % New York 1,575 1,431 144 10.1 % ERCOT 1,181 958 223 23.3 % Other Power Regions 4,890 4,002 888 22.2 % Total electric revenues 16,290 15,060 1,230 8.2 % Other 3,992 2,433 1,559 64.1 % Mark-to-market (losses) gains (633) 110 (743) Total Operating revenues $ 19,649 $ 17,603 $ 2,046 11.6 % __________ (a) % Change in mark-to-market is not a meaningful measure. Sales and Supply Sources. Our sales and supply sources by region are summarized below: 2021 vs. 2020 Supply Source (GWhs) 2021 2020 Variance % Change Nuclear Generation (a) Mid-Atlantic 53,589 52,202 1,387 2.7 % Midwest 93,107 96,322 (3,215) (3.3) % New York 28,291 26,561 1,730 6.5 % Total Nuclear Generation 174,987 175,085 (98) (0.1) % Natural Gas, Oil and Renewables Mid-Atlantic 2,271 2,206 65 2.9 % Midwest 1,083 1,240 (157) (12.7) % New York 1 4 (3) (75.0) % ERCOT 13,187 11,982 1,205 10.1 % Other Power Regions 9,995 11,121 (1,126) (10.1) % Total Natural Gas, Oil and Renewables 26,537 26,553 (16) (0.1) % Purchased Power Mid-Atlantic 13,576 22,487 (8,911) (39.6) % Midwest 561 770 (209) (27.1) % ERCOT 3,256 5,636 (2,380) (42.2) % Other Power Regions 50,212 51,079 (867) (1.7) % Total Purchased Power 67,605 79,972 (12,367) (15.5) % Total Supply/Sales by Region Mid-Atlantic 69,436 76,895 (7,459) (9.7) % Midwest 94,751 98,332 (3,581) (3.6) % New York 28,292 26,565 1,727 6.5 % ERCOT 16,443 17,618 (1,175) (6.7) % Other Power Regions 60,207 62,200 (1,993) (3.2) % Total Supply/Sales by Region 269,129 281,610 (12,481) (4.4) % __________ (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 60 Table of Contents interest on August 6, 2021 as CENG was fully consolidated. See Note 2 — Mergers, Acquisitions, and Dispositions of the Notes to Consolidated Financial Statements for additional information on our acquisition of EDF’s interest in CENG. Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants, which reflects ownership percentage of stations operated by us, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual 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. 2021 2020 Nuclear fleet capacity factor 94.5 % 95.4 % Refueling outage days 262 260 Non-refueling outage days 34 19 ZEC Prices. We are compensated through state programs for the carbon-free attributes of our nuclear generation. ZEC prices have a significant impact on operating revenues. The following table presents the average ZEC prices ($/MWh) for each of our major regions in which state programs have been enacted. Prices reflect the weighted average price for the various delivery periods within each calendar year. 2021 vs. 2020 State (Region) (a) 2021 2020 Variance % Change New Jersey (Mid-Atlantic) $ 10.00 $ 10.00 $ — — % Illinois (Midwest) 16.50 16.50 — — % New York (New York) 20.93 19.59 1.34 6.8 % __________ (a) See Note 7 — Early Plant Retirements of the Notes to Consolidated Financial Statements for additional information on the plants receiving payments through state programs. Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. We also incur capacity costs associated with load served, except in ERCOT. Capacity prices have a significant impact on our operating revenues and purchased power and fuel. The following table presents the average capacity prices ($/MW Day) for each of our major regions. Prices reflect the weighted average price for the various auction periods within each calendar year. 2021 vs. 2020 Location (Region) 2021 2020 Variance % Change Eastern Mid-Atlantic Area Council (Mid-Atlantic and Midwest) $ 174.96 $ 159.50 $ 15.46 9.7 % ComEd (Midwest) 192.45 194.22 (1.77) (0.9) % Rest of State (New York) 98.35 47.81 50.54 105.7 % Southeast New England (Other) 163.66 200.69 (37.03) (18.5) % Electricity Prices. The price of electricity has a significant impact on our operating revenues and purchased power cost. The following table presents the average day-ahead around-the-clock price ($/MWh) for each of our major regions. 61 Table of Contents 2021 vs. 2020 Location (Region) 2021 2020 Variance % Change PJM West (Mid-Atlantic) $ 38.91 $ 20.95 $ 17.96 85.7 % ComEd (Midwest) 34.76 18.96 15.80 83.3 % Central (New York) 29.90 16.36 13.54 82.8 % North (ERCOT) 146.63 22.03 124.60 565.6 % Southeast Massachusetts (Other) (a) 46.38 23.57 22.81 96.8 % __________ (a) Reflects New England, which comprises the majority of the activity in the Other region. For the year ended December 31, 2021 compared to 2020, changes in Operating revenues by region were approximately as follows: 2021 vs. 2020 Variance % Change (a) Description Mid-Atlantic $ (61) (1.3) % • unfavorable wholesale load revenue of $(520) primarily due to lower volumes; partially offset by • favorable settled economic hedges of $365 due to settled prices relative to hedged prices • favorable retail load revenue of $95 primarily due to higher prices Midwest 36 0.9 % • favorable net wholesale load and generation revenue of $540 primarily due to higher prices, partially offset by decreased generation due to higher nuclear outage days; partially offset by • unfavorable settled economic hedges of $(525) due to settled prices relative to hedged prices New York 144 10.1 % • favorable nuclear generation revenue of $75 primarily due to higher prices and lower nuclear outage days • favorable ZEC revenue of $70 due to higher prices and higher nuclear generation ERCOT 223 23.3 % • favorable retail load revenue of $140 primarily due to higher prices in part due to the February 2021 extreme cold weather event • favorable settled economic hedges of $65 due to settled prices relative to hedged prices Other Power Regions 888 22.2 % • favorable settled economic hedges of $655 due to settled prices relative to hedged prices • favorable retail load revenue of $535 due to higher prices and higher volumes; partially offset by • unfavorable wholesale load revenue of $(380) primarily due to lower volumes Other 1,559 64.1 % • favorable gas revenue of $1,375 primarily due to higher prices in part due to the February 2021 extreme cold weather event Mark-to-market (b) (743) • losses on economic hedging activities of $(633) in 2021 compared to gains of $110 in 2020 Total $ 2,046 11.6 % __________ (a) % Change in mark-to-market is not a meaningful measure. (b) See Note 16 — Derivative Financial Instruments of the Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses. 62 Table of Contents Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including supply sources by region, nuclear fleet capacity factor, capacity prices, and electricity prices. The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall purchased power and fuel expense or results of operations, and accelerated nuclear fuel amortization associated with nuclear decommissioning. For the year ended December 31, 2021 compared to 2020, Purchased power and fuel by region were as follows: 2021 vs. 2020 2021 2020 Variance % Change (a) Mid-Atlantic $ 2,320 $ 2,442 $ 122 5.0 % Midwest 1,343 1,121 (222) (19.8) % New York 414 434 20 4.6 % ERCOT 2,006 532 (1,474) (277.1) % Other Power Regions 3,999 3,336 (663) (19.9) % Total electric purchased power and fuel 10,082 7,865 (2,217) (28.2) % Other 3,279 1,904 (1,375) (72.2) % Mark-to-market gains (1,198) (184) 1,014 Total purchased power and fuel $ 12,163 $ 9,585 $ (2,578) (26.9) % __________ (a) % Change in mark-to-market is not a meaningful measure. 63 Table of Contents For the year ended December 31, 2021 compared to 2020, changes in Purchased power and fuel by region were approximately as follows: 2021 vs. 2020 Variance % Change (a) Description Mid-Atlantic $ 122 5.0 % • favorable purchased power and net capacity impact of $80 primarily due to higher nuclear generation, lower load and higher capacity prices earned partially offset by lower cleared capacity volumes • favorable settlement of economic hedges of $70 due to settled prices relative to hedged prices Midwest (222) (19.8) % • unfavorable purchased power and net capacity impact of $(330) primarily due to higher energy prices, lower nuclear generation, lower cleared capacity volumes, and lower capacity prices; partially offset by • favorable nuclear fuel cost of $75 primarily due to accelerated amortization of nuclear fuel and lower nuclear fuel prices New York 20 4.6 % • favorable settlement of economic hedges of $45 due to settled prices relative to hedged prices; partially offset by • unfavorable purchased power and net capacity impact of $(40) primarily due to higher energy prices partially offset by higher nuclear generation and higher capacity prices earned ERCOT (1,474) (277.1) % • unfavorable purchased power of $(755) primarily due to higher energy prices primarily during the February 2021 extreme cold weather event • unfavorable settlement of economic hedges of $(535) due to settled prices relative to hedged prices • unfavorable fuel cost of $(170) primarily due to higher gas prices Other Power Regions (663) (19.9) % • unfavorable purchased power and net capacity impact of $(855) primarily due to higher energy prices, lower generation, lower cleared capacity volumes, and lower capacity prices • unfavorable fuel cost of $(80) primarily due to higher gas prices; partially offset by • net favorable environmental products activity of $270 primarily driven by favorable emissions activity partially offset by unfavorable RPS activity Other (1,375) (72.2) % • unfavorable net gas purchase costs and settlement of economic hedges of $(1,150) • unfavorable accelerated nuclear fuel amortization associated with announced early plant retirements of $(90) Mark-to-market (b) 1,014 • gains on economic hedging activities of $1,198 in 2021 compared to gains of $184 in 2020 Total $ (2,578) (26.9) % __________ (a) % Change in mark-to-market is not a meaningful measure. (b) See Note 16 — Derivative Financial Instruments of the Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses. 64 Table of Contents The changes in Operating and maintenance expense consisted of the following: 2021 vs. 2020 (Decrease) Increase Plant retirements and divestitures (a) $ (484) ARO update (109) Labor, other benefits, contracting, and materials (64) Insurance (45) Cost management program (34) Nuclear refueling outage costs, including the co-owned Salem plants (16) Corporate allocations (14) Acquisition related costs 15 Credit loss expense 21 Asset impairments 27 Separation costs 49 Other 41 Total decrease $ (613) __________ (a) Primarily reflects contractual offset of accelerated depreciation and amortization associated with our previous decision to early retire the Byron and Dresden nuclear facilities. See Note 10 — Asset Retirement Obligations of the Notes to Consolidated Financial Statements for additional information. Depreciation and amortization expense increased for the year ended December 31, 2021 compared to the same period in 2020, 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 increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to gains on sales of equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021 and a gain on sale of our solar business. Inte res t expense, net decreased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to decreased expense related to the CR nonrecourse senior secured term loan credit facility and interest rate swaps, and decreases in interest rates. See Note 17 — Debt and Credit Agreements of the 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, 2021 compared to the same period in 2020, due to activity described in the table below: 2021 2020 Net unrealized gains on NDT funds (a) $ 204 $ 391 Net realized gains on sale of NDT funds (a) 381 70 Interest and dividend income on NDT funds (a) 98 90 Contractual elimination of income tax expense (b) 226 180 Net unrealized (losses) gains from equity investments (c) (160) 186 Other 46 20 Total other, net $ 795 $ 937 65 Table of Contents _________ (a) Unrealized gains, realized gains, and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement Units. In addition, also includes unrealized gains, realized gains, and interest and dividend income on the NDT funds associated with the Byron units as decommissioning-related impacts were not offset starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With the September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations of the Notes to Consolidated Financial Statements for additional information. (b) Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement Units. (c) Net unrealized gains and losses from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021. Effective income tax rates were 148.0% and 29.8% for the years ended December 31, 2021 and 2020, respectively. The higher effective tax rate in 2021 is primarily due to the impacts of the February 2021 extreme cold weather event on Income before income taxes. S ee Note 14 — Income Taxes of the Notes to Consolidated Financial Statements for additional information. Net income attributable to noncontrolling interests increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to CENG's results of operations prior to our acquisition of EDF's interest in CENG on August 6, 2021. Liquidity and Capital Resources For discussion of the year ended December 31, 2020 compared to the year ended December 31, 2019, refer to Liquidity and Capital Resources of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the Form 10. All results included throughout the liquidity and capital resources section are presented on a GAAP basis. Our operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. We annually evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $5.7 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” 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 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 24 — Separation from Exelon of the 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 66 Table of Contents ensure sufficient funds are available. See Note 10 - Asset Retirement Obligations of the Notes to Consolidated Financial Statements for additional information. If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that we address the shortfall by providing additional financial assurances, such as surety bonds, letters of credit, or parent company guarantees for our share of the funding assurance. However, the amount of any assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. No later than two years after shutting down a plant, we must submit a PSDAR to the NRC that includes the planned option for decommissioning the site. Upon issuance of any required financial assurances, subject to satisfying various regulatory preconditions, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an exemption in order for us to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs, if applicable). Any amounts not covered by an exemption would be borne by us without reimbursement. As of December 31, 2021, we are not required to provide any additional financial assurance for TMI Unit 1 under the SAFSTOR scenario that is the planned decommissioning option, as described in the TMI Unit 1 PSDAR filed with the NRC on April 5, 2019. On October 16, 2019, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request to allow the TMI Unit 1 NDT funds to be used for site restoration costs was submitted to the NRC on May 20, 2021 and is pending NRC review. Cash Flows from Operating Activities Our cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Our future cash flows from operating activities may be affected by future demand for, and market prices of, energy and our ability to continue to produce and supply power at competitive costs, as well as to obtain collections from customers and the sale of certain receivables. See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation. The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2021 and 2020: (Decrease) increase in cash flows from operating activities Net income $ (662) Adjustments to reconcile net income to cash: Non-cash operating activities (287) Option premiums paid, net (199) Collateral posted, net (609) Income taxes 70 Pension and non-pension postretirement benefit contributions (4) Changes in working capital and other noncurrent assets and liabilities (231) Decrease in cash flows from operating activities $ (1,922) 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 2021 and 2020 were as follows: • See Note 22 —Supplemental Financial Information of the Notes to Consolidated Financial Statements and the Consolidated Statement of Cash Flows for additional information on non-cash operating activities . 67 Table of Contents • Option premiums paid relate to options contracts that we purchase and sell as part of our established policies and procedures to manage risks associated with market fluctuations in commodity prices. See Note 16 — Derivative Financial Instruments of the Notes to Consolidated Financial Statements for additional information on derivative contracts. • Depending upon whether we are in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from our counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the over-the-counter markets. See Note 16 — Derivative Financial Instruments of the Notes to Consolidated Financial Statements for additional information on collateral. • See Note 14 —Income Taxes of the Notes to Consolidated Financial Statements and the Consolidated Statements of Cash Flows for additional information on income taxes. • Changes in working capital and other noncurrent assets and liabilities include a decrease in Accounts receivable resulting from the impact of cash received in 2020 related to the revolving accounts receivable financing arrangement entered into on April 8, 2020 and an increase in Accounts payable and accrued expenses resulting from the impact of certain penalties for natural gas delivery associated with the February 2021 extreme cold weather event and increases in natural gas prices. See Note 6 — Accounts Receivable and Note 3 — Regulatory Matters of the Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivable and on the February 2021 extreme cold weather event, respectively. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2021 and 2020: Increase (decrease) in cash flows from investing activities Capital expenditures $ 418 Investment in NDT fund sales, net (18) Collection of DPP 131 Proceeds from sales of assets and businesses 832 Other investing activities (39) Increase in cash flows from investing activities $ 1,324 Significant investing cash flow impacts for 2021 and 2020 were as follows: • Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending. • See Note 6 — Accounts Receivable of the Notes to Consolidated Financial Statements for additional information on the Collection of DPP . • Proceeds from sales of assets and businesses increased primarily due to the sale of a significant portion of our solar business and a biomass facility and proceeds received on sales of equity investments. See Note 2 — Mergers, Acquisitions, and Dispositions of the Notes to Consolidated Financial Statements for additional information on the sale of our solar business and biomass facility. 68 Table of Contents 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, 2021 and 2020: Increase (decrease) in cash flows from financing activities Changes in short-term borrowings, net $ 722 Long-term debt, net 1,776 Changes in money pool with Exelon (570) Acquisition of noncontrolling interest (885) Distributions to member (98) Other financing activities 24 Increase in cash flows from financing activities $ 969 Significant financing cash flow impacts for 2021 and 2020 were as follows: • Changes in short-term borrowings, net , is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 17 - Debt and Credit Agreements of the Notes to Consolidated Financial Statements for additional information on short-term borrowings. • Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for additional information. • Changes in money pool with Exelon are driven by short-term borrowing needs. 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. • See Note 2 — Mergers, Acquisitions, and Dispositions of the Notes to Consolidated Financial Statements for additional information related to the acquisition of CENG noncontrolling interest. • Other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on debt issuances. Debt Issuances and Redemptions See Note 17 — Debt and Credit Agreements of the Notes to Consolidated Financial Statements for additional information on our long-term debt. Debt activity for 2021 and 2020 was as follows: During 2021, the following long-term debt was issued: Type Interest Rate Maturity Amount Use of Proceeds West Medway II Nonrecourse Debt (a) 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. __________ (a) See Note 17 — Debt and Credit Agreements of the Notes to Consolidated Financial Statements for additional information on 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. 69 Table of Contents During 2020, the following long-term debt was issued: Type Interest Rate Maturity Amount Use of Proceeds Senior Notes 3.25 % June 1, 2025 $ 900 Repay existing indebtedness and for general corporate purposes. Constellation Renewables Nonrecourse Debt (a) LIBOR + 2.75% December 15, 2027 750 Repay existing indebtedness and for general corporate purposes. Energy Efficiency Project Financing (b) 2.53% - 3.95% February 28, 2021 - March 31, 2021 6 Funding to install energy conservation measures. __________ (a) See Note 17 — Debt and Credit Agreements of the Notes to Consolidated Financial Statements for additional information of nonrecourse debt. (b) 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 retired and/or redeemed: 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 __________ (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 Notes to Consolidated Financial Statements for additional information on the mirror debt. (b) See Note 17 — Debt and Credit Agreements of the 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. During 2020, the following long-term debt was retired and/or redeemed: Type Interest Rate Maturity Amount Senior Notes 2.95% January 15, 2020 $ 1,000 Senior Notes 4.00% October 1, 2020 550 Senior Notes (a) 5.15% December 1, 2020 550 Tax-Exempt Bonds 2.50% - 2.70% December 1, 2025 - June 1, 2036 412 CR Nonrecourse Debt (b) 3-month LIBOR + 3.00% November 30, 2024 796 Continental Wind Nonrecourse Debt (b) 6.00% February 28, 2033 33 Antelope Valley DOE Nonrecourse Debt (b) 2.29% - 3.56% January 5, 2037 23 RPG Nonrecourse Debt (b) 4.11% March 31, 2035 9 Energy Efficiency Project Financing 3.71% December 31, 2020 4 NUKEM 3.15% September 30, 2020 3 SolGen Nonrecourse Debt 3.93% September 30, 2036 3 Energy Efficiency Project Financing 4.12% November 30, 2020 1 __________ (a) The senior notes are legacy mirror debt that were previously held at Exelon and Constellation. As part of the 2012 merger, Exelon and Constellation assumed intercompany loan agreements that mirrored the terms and amounts of external 70 Table of Contents obligations held by Exelon, resulting in notes payable to related parties in the Consolidated Balance Sheets. See Note 17 — Debt and Credit Agreements of the Notes to Consolidated Financial Statements for additional information on the mirror debt. (b) See Note 17 — Debt and Credit Agreements of the Notes to Consolidated Financial Statements for additional information of nonrecourse debt. 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. Credit Matters and Cash Requirements We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of December 31, 2021, our credit facilities included $6.6 billion in aggregate total commitments of which $3.4 billion was available to support additional commercial paper and of which no financial institution has more than 8% of the aggregate commitments. In connection with our separation from Exelon, we entered into two new credit agreements that replaced our syndicated revolving credit facility. Under the new agreements, we have access to credit facilities with aggregate bank commitments of $5.7 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during 2021 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 lost our investment grade credit rating as of December 31, 2021, we would have been required to provide incremental collateral of approximately $2.1 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which was well within the $3.4 billion of available credit capacity of our revolver as of December 31, 2021. See Note 16 — Derivative Financial Instruments and Note 17 — Debt and Credit Agreements of the Notes to Consolidated Financial Statements for additional information. Capital Expenditures Our most recent estimate of capital expenditures for plant additions and improvements is approximately $1.7 billion for 2022 and approximately $2.9 billion for the period from 2023 to 2024. Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Approximately 50% of projected capital expenditures are for the acquisition of nuclear fuel, with the remaining amounts primarily reflecting additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages). We anticipate that we will fund capital expenditures with a combination of internally generated funds and borrowings. Cash Requirements for Other Financial Commitments The following table summarizes our future estimated cash payments as of December 31, 2021 under existing financial commitments: 71 Table of Contents 2022 Beyond 2022 Total Time Period Long-term debt $ 1,218 $ 4,878 $ 6,096 2022 - 2042 Interest payments on long-term debt (a) 252 3,011 3,263 2022 - 2042 Operating leases (b) 35 611 646 2022 - 2056 Purchase power obligations (c) 620 1,109 1,729 2022 - 2036 Fuel purchase agreements (d) 1,020 4,452 5,472 2022 - 2054 Other purchase obligations (e) 1,159 1,231 2,390 2022 - 2046 SNF obligation — 1,210 1,210 2022 - 2035 Pension contributions (f) 192 93 285 2022 - 2027 Total cash requirements $ 4,496 $ 16,595 $ 21,091 __________ (a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 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, 2021. (b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $57 million and $315 million for 2022 and thereafter, respectively and $372 million in total. (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, 2021 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 2027 are not included. See Note 19 — Commitments and Contingencies and Note 3 — Regulatory Matters of the 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 Notes to the Consolidated Financial Statements. Item Location within Notes to the Consolidated Financial Statements Long-term debt Note 17 — Debt and Credit Agreements Interest payments on long-term debt Note 17 — Debt and Credit Agreements Operating leases Note 11 — Leases SNF obligation Note 19 — Commitments and Contingencies Project Financing Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by a specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. Lenders do not have recourse against us in the event of a default. If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to repay the debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. See Note 17 — Debt and Credit Agreements of the Notes to Consolidated Financial Statements for additional information on project finance credit facilities and nonrecourse debt. 72 Table of Contents 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 Notes to Consolidated Financial Statements for additional information on our credit facilities. Capital Structure At December 31, 2021, our capital structure consisted of the following: Percentage of Capital Structure Commercial paper and notes payable 10 % Long-term debt 29 % Long-term debt to affiliates 2 % Member’s equity 59 % 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 Notes to Consolidated Financial Statements for additional information on collateral provisions. On February 24, 2021, S&P lowered our senior unsecured debt rating to 'BBB-' from 'BBB' in response to the financial impacts of the February 2021 weather event and outages at our Texas-based generating assets. See Note 3 — Regulatory Matters of the Notes to Consolidated Financial Statements for additional information. The S&P rating change did not materially impact our financial statements. Furthermore, there were no material increases in required collateral or financial assurances or material impacts to our anticipated access to liquidity or cost of financing. At separation S&P and Moody's affirmed the senior unsecured ratings of BBB- and Baa2, respectively. Fitch also affirmed their final rating of BBB, prior to formally withdrawing coverage on January 5th. We will only be engaging S&P and Moody's for ratings coverage following separation.