Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollars in millions except per share data, unless otherwise noted)

Executive Overview

We are a supplier of clean energy. Our generating capacity includes primarily nuclear, wind, solar, natural gas and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions.

Significant Transactions and Developments

Nuclear PTC

As a result of the enactment of the IRA, we qualify for certain federal government incentives through eligible activities. These incentives include both refundable and transferable tax credits. Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh. We have determined that we will meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust annually for inflation over the duration of the program, and the benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party. For the three months ended March 31, 2024, our Consolidated Statements of Operations and Comprehensive Income includes an estimate of $304 million in Operating revenues for nuclear PTC earned based on qualifying production volumes during the period. See Note 5 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.

Share Repurchase Program

On April 30, 2024, our Board of Directors approved a $1 billion increase to the previously announced share repurchase program, authorizing total repurchases of up to $3 billion. As of the date of filing, we have purchased a total of approximately 13.5 million shares for a total cost of $1.5 billion, with remaining authority to purchase up to $1.5 billion of the Company's outstanding common stock. See Note 14 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

Other Key Business Drivers

Russia and Ukraine Conflict

We are closely monitoring developments of the ongoing Russia and Ukraine conflict, including United States, United Kingdom, European Union, and Canadian sanctions, and legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit energy deliveries. We are cognizant of the recent passage of the U.S. legislation known as “Prohibiting Russian Uranium Imports Act” that is expected to be signed by the President. Among its provisions, the legislation bans the import of low-enriched uranium into the U.S. that is produced in Russia or by Russian entities, absent a waiver from the DOE. The passage of this bill will allow the Department of Energy to begin the process of distributing billions of dollars that were previously appropriated to support expansion of the domestic nuclear fuel cycle within the United States to improve carbon-free energy security. 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 into 2029, which is the date multiple suppliers are expected to have incremental additional capacity online.

Environmental Regulation

Regulation of GHGs from Power Plants under the Clean Air Act. In April 2024, EPA issued a final rule that regulates greenhouse gases from existing coal, new natural gas fired power plants, and existing oil/gas steam generators under Clean Air Act section 111. The applicable standards are subcategorized by retirement date for existing coal and capacity factor for existing gas. We are evaluating market impacts of this rule, which will be affected by upcoming state implementation and expected litigation. EPA is soliciting comment on approaches for regulating GHGs from existing gas plants in a docket that closes in May 2024.

Critical Accounting Policies and Estimates

Management makes a number of significant estimates, assumptions, and judgements in the preparation of our financial statements. At March 31, 2024, our critical accounting policies and estimates had not changed significantly from December 31, 2023, with the exception of accounting for government grants and disclosure of government assistance. See Note 5 — Government Assistance of the Combined Notes to Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in our 2023 Form 10-K for further information.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the three months ended March 31, 2024 compared to the same period in 2023. For additional information regarding the financial results for the three months ended March 31, 2024 and 2023 see the discussions of Results of Operations below.

Three Months Ended March 31,Favorable Variance
20242023
GAAP Net Income (Loss) Attributable to Common Shareholders$883$96$787

Adjusted (non-GAAP) Operating Earnings. We utilize Adjusted (non-GAAP) Operating Earnings (and/or its per share equivalent) in our internal analysis, and in communications with investors and analysts, as a consistent measure for comparing our financial performance and discussing the factors and trends affecting our business. The presentation of Adjusted (non-GAAP) Operating Earnings is intended to complement and should not be considered an alternative to, nor more useful than, the presentation of GAAP Net Income.

The table below provides a reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings. Adjusted (non-GAAP) Operating Earnings is not a standardized financial measure and may not be comparable to other companies’ presentations of similarly titled measures.

Unless otherwise noted, the income tax impact of each reconciling adjustment between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all adjustments except the NDT fund investment returns, which are included in decommissioning-related activities, the marginal statutory income tax rate was 25.1% for both the three months ended March 31, 2024 and 2023. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 54.8% and 129.2% for the three months ended March 31, 2024 and 2023, respectively. The following table provides a reconciliation between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings for the three months ended March 31, 2024 compared to the same period in 2023.

Three Months Ended March 31,
20242023
Earnings Per Share**(a)**Earnings Per Share**(a)**
Net Income (Loss) Attributable to Common Shareholders$883$2.78$96$0.29
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $57 and $76, respectively)(b)(170)(0.53)2270.69
Plant Retirements and Divestitures (net of taxes of $4 and $6, respectively)120.04(19)(0.06)
Decommissioning-Related Activities (net of taxes of $139 and $117, respectively)(c)(67)(0.21)(74)(0.23)
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $1 and $3, respectively)20.01(10)(0.03)
Separation Costs (net of taxes of $2 and $8, respectively)(d)50.02230.07
ERP System Implementation Costs (net of taxes of $1 and $1, respectively)(e)40.0120.01
Change in Environmental Liabilities (net of taxes of $— and $4, respectively)——120.04
Income Tax-Related Adjustments(f)(88)(0.28)——
Noncontrolling Interests (net of taxes of $— and $—, respectively)(g)(2)(0.01)(1)—
Adjusted (non-GAAP) Operating Earnings$579$1.82$256$0.78

(a)Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 318 million and 328 million for the three months ended March 31, 2024 and 2023, respectively.

(b)Includes mark-to-market on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments.

(c)Reflects all gains and losses associated with NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units.

(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)Reflects costs related to a multi-year ERP system implemented in the first quarter of 2024.

(f)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.

(g)Represents elimination of the noncontrolling interests related to certain adjustments.

Results of Operations

Three Months Ended March 31,Favorable (Unfavorable) Variance
20242023
Operating revenues$6,161$7,565$(1,404)
Operating expenses
Purchased power and fuel3,4175,7292,312
Operating and maintenance1,4861,432(54)
Depreciation and amortization306267(39)
Taxes other than income taxes139132(7)
Total operating expenses5,3487,5602,212
Gain (loss) on sales of assets and businesses—2626
Operating income (loss)81331782
Other income and (deductions)
Interest expense, net(127)(107)(20)
Other, net36231448
Total other income and (deductions)23520728
Income (loss) before income taxes1,048238810
Income tax (benefit) expense165131(34)
Equity in income (losses) of unconsolidated affiliates—(5)5
Net income (loss)883102781
Net income (loss) attributable to noncontrolling interests—6(6)
Net income (loss) attributable to common shareholders$883$96787

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023. The variance in Net income (loss) attributable to common shareholders was favorable by $787 million primarily due to:

  • Favorable mark-to-market activity and other fair value adjustments;

  • Favorable net market and portfolio conditions primarily driven by increased load and generation-to-load optimization;

  • Favorable nuclear PTCs related to the IRA beginning in 2024; and

  • Favorable impacts of nuclear outages.

The favorable items were partially offset by:

  • Unfavorable ZEC and CMC program revenues primarily due to lower pricing in the current year, as well as estimated refunds required by certain state sponsored programs in connection with the nuclear PTCs; and

  • Higher labor, contracting and materials.

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 RTO/ISO 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 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.

Wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operations are reported under Other and not allocated to a region.

For the three months ended March 31, 2024 compared to 2023, Operating revenues were as follows:

Three Months Ended March 31,
20242023Variance% Change**(a)**
Mid-Atlantic$1,242$1,245$(3)(0.2)%
Midwest1,0941,032626.0%
New York513535(22)(4.1)%
ERCOT32116915289.9%
Other Power Regions1,6241,791(167)(9.3)%
Total reportable segment electric revenues4,7944,772220.5%
Other1,3031,864(561)(30.1)%
Mark-to-market gains (losses)64929(865)
Total Operating revenues$6,161$7,565$(1,404)(18.6)%

(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:

Three Months Ended March 31,
Supply Source (GWhs)20242023Variance% Change
Nuclear Generation(a)
Mid-Atlantic13,19013,18190.1%
Midwest23,92022,9869344.1%
New York6,0796,296(217)(3.4)%
ERCOT2,202—2,202100.0%
Total Nuclear Generation45,39142,4632,9286.9%
Natural Gas, Oil, and Renewables
Mid-Atlantic86872214620.2%
Midwest339339——%
ERCOT(b)3,5163,2862307.0%
Other Power Regions3,5512,90464722.3%
Total Natural Gas, Oil, and Renewables8,2747,2511,02314.1%
Purchased Power
Mid-Atlantic3,3704,035(665)(16.5)%
Midwest308423(115)(27.2)%
ERCOT6651,351(686)(50.8)%
Other Power Regions10,3999,9174824.9%
Total Purchased Power14,74215,726(984)(6.3)%
Total Supply/Sales by Region
Mid-Atlantic17,42817,938(510)(2.8)%
Midwest24,56723,7488193.4%
New York6,0796,296(217)(3.4)%
ERCOT(b)6,3834,6371,74637.7%
Other Power Regions13,95012,8211,1298.8%
Total Supply/Sales by Region68,40765,4402,9674.5%

(a)Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants.

(b)2023 values have been revised from those previously reported to reflect gross generation inclusive of behind the meter consumption.

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 and STP, which are operated by PSEG and STPNOC, respectively. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at its net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.

Three Months Ended March 31,
20242023
Nuclear fleet capacity factor93.3%92.8%
Refueling outage days7886
Non-refueling outage days109

Nuclear PTC. Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh. We have determined that we will meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party.

Many of the state sponsored programs (i.e., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. See Note 5 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.

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 three months ended March 31, 2024 and 2023.

Three Months Ended March 31,
State (Region)(a)20242023Variance% Change
New Jersey (Mid-Atlantic)(b)$10.00$9.88$0.121.2%
Illinois (Midwest)0.3012.01(11.71)(97.5)%
New York (New York)18.2721.38(3.11)(14.5)%

(a)See ITEM 1. BUSINESS, Environmental Matters of our 2023 Form 10-K for additional information on the plants receiving payments through state programs.

(b)The ZEC price is expected to be $10.00/MWh for each delivery period and is subject to an annual update once full year generation is known. Following the latest annual update, on August 16, 2023 the ZEC price for the delivery period beginning June 1, 2022 through May 31, 2023 was calculated to be $9.88.

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 and $32.50 per MWh for the period June 1, 2023 through May 31, 2024). 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. The average CMC prices per MWh were $7.55 and $1.51 for the three months ended March 31, 2024 and 2023, respectively.

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 prices for the various auction periods within the three months ended March 31, 2024 and 2023.

Three Months Ended March 31,
Location (Region)20242023Variance% Change
Eastern Mid-Atlantic Area Council (Mid-Atlantic)$49.49$97.86$(48.37)(49.4)%
ComEd (Midwest)34.1368.96(34.83)(50.5)%
Rest of State (New York)106.52103.672.852.7%
Southeast New England (Other)66.67126.67(60.00)(47.4)%

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

Three Months Ended March 31,
Location (Region)20242023Variance% Change
PJM West (Mid-Atlantic)$34.25$33.12$1.133.4%
ComEd (Midwest)26.0726.80(0.73)(2.7)%
Central (New York)34.8830.164.7215.6%
North (ERCOT)25.7223.252.4710.6%
Southeast Massachusetts (Other)(a)44.1851.84(7.66)(14.8)%

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

For the three months ended March 31, 2024 compared to 2023, changes in Operating revenues by region were approximately as follows:

Three Months Ended March 31
Variance% Change**(a)**Significant Drivers
Mid-Atlantic$(3)(0.2)%• unfavorable wholesale load revenue of ($75) due to lower contracted energy prices and lower volumes; partially offset by • favorable estimated nuclear PTC revenue of $85
Midwest626.0%• favorable estimated nuclear PTC revenue of $200 • favorable settled economic hedges of $40 due to settled prices relative to hedged prices; partially offset by • unfavorable net ZEC and CMC program revenue of ($100) due to decrease in ZEC price in current planning year and estimated pass through associated with nuclear PTC • unfavorable net generation and wholesale load revenue of ($50) primarily due to lower load volume, partially offset by higher generation volumes and net capacity revenue
New York(22)(4.1)%• no individually significant drivers
ERCOT15289.9%• favorable settled economic hedges of $90 due to settled prices relative to hedged prices • favorable net generation and wholesale load revenue of $75 due to higher load volumes and higher contracted energy prices
Other Power Regions(167)(9.3)%• unfavorable wholesale load revenue of ($135) primarily due to lower contracted prices partially offset by higher load volume • unfavorable settled economic hedges of ($55) due to settled prices relative to hedged prices
Other(561)(30.1)%• unfavorable gas revenue, inclusive of settled economic hedges, of ($315) primarily due to lower gas prices • unfavorable revenues in the United Kingdom, inclusive of settled economic hedges, of ($215) primarily due to lower energy prices
Mark-to-market(b)(865)• gains on economic hedging activities of $64 in 2024 compared to gains of $929 in 2023
Total$(1,404)(18.6)%

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

(b)See Note 10 — 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.

Wholesale and retail natural gas activity, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a region.

For the three months ended March 31, 2024 compared to 2023, Purchased power and fuel expense were as follows:

Three Months Ended March 31,
20242023Variance% Change**(a)**
Mid-Atlantic$568$554$(14)(2.5)%
Midwest391343(48)(14.0)%
New York16927410538.3%
ERCOT11211754.3%
Other Power Regions1,2561,54328718.6%
Total electric purchased power and fuel2,4962,83133511.8%
Other1,0451,70365838.6%
Mark-to-market losses (gains)(124)1,1951,319
Total Purchased power and fuel$3,417$5,729$2,31240.4%

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

For the three months ended March 31, 2024 compared to 2023, changes in Purchased power and fuel expense by region were approximately as follows:

Three Months Ended March 31
Variance% Change**(a)**Significant Drivers
Mid-Atlantic$(14)(2.5)%• no individually significant drivers
Midwest(48)(14.0)%• no individually significant drivers
New York10538.3%• favorable settlement of economic hedges of $125 due to settled prices relative to hedged prices
ERCOT54.3%• no individually significant drivers
Other Power Regions28718.6%• favorable purchased power and fuel of $285 primarily due to lower energy prices partially offset by higher load served
Other65838.6%• favorable net gas purchases, inclusive of settled economic hedges, of $470 primarily due to lower gas prices • favorable purchases in the United Kingdom, inclusive of settled economic hedges, of $165 primarily due to lower energy prices
Mark-to-market(b)1,319• gains on economic hedging activities of $124 in 2024 compared to losses of ($1,195) in 2023
Total$2,31240.4%

.__________

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

(b)See Note 10 — 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:

Three Months Ended March 31
2024 vs. 2023
Increase (Decrease)
Labor, contracting, and materials(a)$111
Change in environmental liabilities(16)
Separation costs(23)
Nuclear refueling outage costs, including the co-owned Salem and STP generating units(37)
Other19
Total increase$54

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

Other, net was favorable for the three months ended March 31, 2024 compared to the same period in 2023, due to activity described in the table below:

Three Months Ended March 31,
Income (Deductions)
20242023
Decommissioning-related activities(a)$296$280
Non-service net periodic benefit credit(b)(2)14
Net realized and unrealized gains (losses) from equity investments47(5)
Other(c)2125
Other, net$362$314

(a)Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 7 — Nuclear Decommissioning and Note 16 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.

(b)The non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 9 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.

(c)Includes amounts we billed Exelon for services pursuant to the TSA.

Effective income tax rates were 15.7% and 55.0% for the three months ended March 31, 2024 and 2023, respectively. The change in effective tax rate in 2024 is primarily due to the increase in pre-tax book income inclusive of the nuclear PTC, which is not taxable, and a state tax benefit due to a change in forecasted apportionment. See Note 8 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Liquidity and Capital Resources

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

Our operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. We annually evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions

deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $6.3 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 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our debt and credit agreements.

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 for radiological decommissioning of 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 7 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information regarding the latest funding status report filed with the NRC.

As of March 31, 2024, the TMI Unit 1 NDT is fully funded 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. Additionally, as of March 31, 2024, we have adequate NDT funds for the remaining radiological decommissioning costs at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Liquidity and Capital Resources — NRC Minimum Funding Requirements of our 2023 Form 10-K for information regarding the risk of additional financial assurance for shutdown units.

Cash Flows from Operating Activities

Our cash flows from operating activities primarily result from the sale of electric energy and energy-related products and sustainable solutions 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.

The following table provides a summary of the change in cash flows from operating activities for the three months ended March 31, 2024 and 2023:

Three Months Ended March 31,
Cash flows from operating activities20242023Change
Net income (loss)$883$102$781
Adjustments to reconcile net income (loss) to cash:
Collateral received (posted), net297(261)558
Option premiums received (paid), net74(23)97
Pension and non-pension postretirement benefit contributions(177)(10)(167)
Changes in working capital and other noncurrent assets and liabilities(a)(2,037)(1,433)(604)
Total non-cash operating activities(b)237691(454)
Net cash flows provided by (used in) operating activities$(723)$(934)$211

(a)Includes changes in Accounts receivable, 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, 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 16 — 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. Significant operating cash flow impacts for the three months ended March 31, 2024 and 2023 were as follows:

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

  • Option premiums paid, net** relates 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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on derivative contracts.

  • Increase in cash outflows for pension and non-pension postretirement benefit contributions is primarily due to our annual qualified pension contribution of $161 million made in February 2024. See Note 9 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and non-pension postretirement benefit plans.

  • A net increase in cash outflows for changes in working capital and other noncurrent assets and liabilities primarily relates to a decrease in Other assets and liabilities, primarily driven by an increase in cash collections applied to DPP causing an inverse change in other assets and liabilities, due to a decrease in the drawn customer accounts receivable Facility balance in 2024 compared to 2023. Additionally, there was an increase in Other deferred debits and other assets, mainly driven by the nuclear PTC in the current year. See Note 5 — Government Assistance and Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC and the sales of customer accounts receivable, respectively.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the three months ended March 31, 2024 and 2023:

Three Months Ended March 31,
Cash flows from investing activities20242023Change
Collection of DPP, net$1,644$926$718
Acquisitions of assets and businesses(14)(17)3
Investment in NDT funds, net(68)(53)(15)
Proceeds from sales of assets and businesses724(17)
Capital expenditures(738)(660)(78)
Other investing activities(1)(1)—
Net cash flows provided by (used in) investing activities$830$219$611

Significant investing cash flow impacts for the three months ended March 31, 2024 and 2023 were as follows:

  • Collection of DPP, net** increased primarily due to the increased cash collections applied to DPP as a result of a decrease in the drawn Facility balance in 2024 compared to 2023. In addition, more cash collections were reinvested in the Facility in 2024. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

  • Increase in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See Liquidity and Capital Resources — Credit Matters and Cash Requirements of our 2023 Form 10-K for information for additional information on projected capital expenditure spending.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the three months ended March 31, 2024 and 2023:

Three Months Ended March 31,
Cash flows from financing activities20242023Change
Long-term debt, net$868$1,323$(455)
Repurchases of common stock(499)(231)(268)
Dividends paid on common stock(112)(93)(19)
Changes in short-term borrowings, net(135)(454)319
Other financing activities(38)(22)(16)
Net cash flows provided by (used in) financing activities$84$523$(439)

Significant financing cash flow impacts for the three months ended March 31, 2024 and 2023 were as follows:

  • Long-term debt, net,** varies due to debt issuances and redemptions each year. Refer to Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

  • Repurchases of common stock** is related to our share repurchase program that commenced in March 2023. See Note 14 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

  • Refer to ITEM 5 — MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES in our 2023 Form 10-K for further information on dividend restrictions. See below for quarterly dividends declared.

  • Changes in short-term borrowings, net**, is driven by repayments on and issuances of notes due within one year of issuance. Refer to Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.

Dividends

Quarterly dividends declared by our Board of Directors during the three months ended March 31, 2024 and for the second quarter of 2024 were as follows:

PeriodDeclaration DateShareholder of Record DateDividend Payable DateCash per Share
First Quarter of 2024February 26, 2024March 8, 2024March 19, 2024$0.3525
Second Quarter of 2024May 1, 2024May 29, 2024June 10, 2024$0.3525

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 March 31, 2024, we have access to facilities with aggregate bank commitments of $6.3 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during the first quarter of 2024 to fund our short-term liquidity needs, when necessary. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2023 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.

If we had lost our investment grade credit rating as of March 31, 2024, we would have been required to provide incremental collateral estimated to be approximately $1.9 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 three notch downgrade by S&P or Moody's from their current levels of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of March 31, 2024, we had $3.0 billion of available capacity under our credit facilities and $0.6 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding available capacity under our credit facilities and cash on hand, we could be required to access additional liquidity through the capital markets. See Note 10 — Derivative Financial Instruments and Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Pension and Other Postretirement Benefits

We consider various factors when making pension funding decisions, including actuarially-determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, 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 improve funded status with the objective of achieving 100% funded status over time. Based on this funding strategy and current market conditions, which are both subject to change, our annual qualified pension contribution was made in February 2024 for $161 million.

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 parts of our plans. For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid. The estimated benefit payments to the non-qualified pension plans in 2024 are approximately $23 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans, is $14 million. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2023 Form 10-K for additional information on pension and other postretirement benefits.

Cash Requirements for Other Financial Commitments

Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2023 Form 10-K for additional information on our cash requirements for financial commitments.

Sales of Customer Accounts Receivable

We have an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables, which expires on 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 our 2023 Form 10-K 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 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities.

Security Ratings

Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings.

Our borrowings are not subject to default or prepayment as a result of a downgrade of our securities, although such a downgrade could increase fees and interest charges under our 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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

Our credit ratings from S&P and Moody's are BBB+ and Baa1, respectively, as of March 31, 2024. On March 22, 2024, Moody's raised our issuer credit rating to 'Baa1' from 'Baa2' citing confidence in our ability to maintain credit metrics and strong financial performance.

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