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, 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

Separation from Exelon

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate its competitive generation and customer-facing energy businesses into a stand-alone publicly traded company (the "separation"). Exelon completed the separation on February 1, 2022. We incurred separation costs of $30 million and $37 million for the three months ended March 31, 2023 and 2022, respectively, which are primarily recorded in Operating and maintenance expense. The separation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information.

Share Repurchase Program

On February 16, 2023, our Board of Directors announced a share repurchase program with a $1 billion purchase authority without expiration. Repurchases under this program commenced in March 2023. During the three months ended March 31, 2023, we repurchased from the open market 3.2 million shares of our common stock for a total cost of $251 million. See Note 13 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

Other Key Business Drivers

PJM Performance Bonuses

On December 23, 2022, and continuing through the morning of December 25, 2022, winter storm Elliott blanketed the entirety of PJM’s footprint with record low temperatures and extreme weather conditions. A significant portion of PJM's fossil generation fleet failed to perform as reserves were called. PJM issued invoices in April 2023 that reflected generator’s gross bonuses and non-performance charges. In accordance with its tariff, funds collected from those charges are redistributed to generating resources that overperformed during the event, including our nuclear fleet. As a result of additional information received, we recognized an increase in revenue of $38 million (pre-tax) during the three months ended March 31, 2023. Our total estimated receivable for performance bonuses (net of non-performance charges) is $148 million as of March 31, 2023, and continues to require the application of significant judgement and assumptions that include potential impacts of generator defaults and litigation. It is reasonably possible that the ultimate impact to our consolidated financial statements could differ materially once these uncertainties are resolved.

Russia and Ukraine Conflict

We are closely monitoring developments of the Russia and Ukraine conflict including United States sanctions against Russian energy exports, the potential for sanctions on Russian nuclear fuel supply, and enrichment activities, as well as yet undefined action by Russia to limit energy deliveries. To-date, our nuclear fuel deliveries have not been affected by the Russia and Ukraine conflict. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel and generally have enough nuclear fuel to support all our

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refueling needs for multiple years regardless of sanctions. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. We are taking this affirmative action by working with our diverse set of suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term and provide the necessary fuel to bridge potential Russian supply disruption through 2028, which is the date multiple suppliers are expected to have incremental capacity online. We are also continuing to work with federal policymakers and other stakeholders to facilitate the expansion of the domestic nuclear fuel cycle within the United States to improve carbon-free energy security.

Hedging Strategy

We are exposed to commodity price risk associated with the unhedged portion of our electricity portfolio. We enter into non-derivative and derivative contracts, including options, swaps, and forward and futures contracts, all with credit-approved counterparties, to hedge this anticipated exposure. For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, historically we have used a three-year ratable sales plan to align our hedging strategy with our financial objectives. As a result, our prompt three-year merchant revenues have been hedged on an approximate rolling 90%/60%/30% basis. We may also enter into transactions that are outside of this ratable hedging program. As of March 31, 2023, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 95%-98% and 77%-80% for 2023 and 2024, respectively. Going forward, we will continue to be proactive in managing our overall portfolio exposure to commodity risk, but will also manage our generation portfolio through the nuclear PTC, which, starting in 2024, provides downside commodity price protection for our nuclear units. Like our traditional hedging program, the nuclear PTC is an important tool in managing commodity risk.

We procure natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 60% of our uranium concentrate requirements from 2023 through 2027 are supplied by three suppliers. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments, including the Russia and Ukraine conflict and United States sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements.

See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

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, 2023, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2022. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in our 2022 Form 10-K for further information.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income Attributable to Common Shareholders for the three months ended March 31, 2023 compared to the same period in 2022. For additional information regarding the financial results for the three months ended March 31, 2023 and 2022 see the discussions of Results of Operations below.

Three Months Ended March 31,Unfavorable Variance
20232022
GAAP Net Income Attributable to Common Shareholders$96$106$(10)

Adjusted EBITDA (non-GAAP). In analyzing and planning for our business, we supplement our use of GAAP Net Income Attributable to Common Shareholders with Adjusted EBITDA (non-GAAP) as a performance measure. Adjusted EBITDA (non-GAAP) reflects an additional way of viewing our business that, when viewed with our GAAP results and the accompanying reconciliation to GAAP Net Income Attributable to Common Shareholders included in the table below, may provide a more complete understanding of factors and trends affecting our business. Adjusted EBITDA (non-GAAP) should not be relied upon to the exclusion of GAAP financial measures and is, by definition, an incomplete understanding of our business, and must be considered in conjunction with GAAP measures. In addition, Adjusted EBITDA (non-GAAP) is neither a standardized financial measure, nor a presentation defined under GAAP and may not be comparable to other companies’ presentations of similarly titled financial measures or deemed more useful than the GAAP information provided elsewhere in this report.

The following table provides a reconciliation between Net Income Attributable to Common Shareholders as determined in accordance with GAAP and Adjusted EBITDA (non-GAAP) for the three months ended March 31, 2023 compared to the same period in 2022.

Three Months Ended March 31,
20232022
Net Income Attributable to Common Shareholders$96$106
Income Taxes131(53)
Depreciation and Amortization267280
Interest Expense, Net10756
Unrealized Loss on Fair Value Adjustments(a)297118
Plant Retirements and Divestitures(27)—
Decommissioning-Related Activities(b)(240)354
Pension & OPEB Non-Service Credits(14)(25)
Separation Costs(c)3037
ERP System Implementation Costs(d)65
Change in Environmental Liabilities17—
Noncontrolling Interests(e)(12)(12)
Adjusted EBITDA (non-GAAP)$658$866

(a)Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments.

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

(c)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.

(d)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation.

(e)Reflects elimination from results for the noncontrolling interests related to certain adjustments.

Results of Operations

Three Months Ended March 31,Favorable (Unfavorable) Variance
20232022
Operating revenues$7,565$5,591$1,974
Operating expenses
Purchased power and fuel5,7293,550(2,179)
Operating and maintenance1,4321,205(227)
Depreciation and amortization26728013
Taxes other than income taxes1321375
Total operating expenses7,5605,172(2,388)
Gain on sales of assets and businesses2616(10)
Operating income31435(404)
Other income and (deductions)
Interest expense, net(107)(56)(51)
Other, net314(318)632
Total other income and (deductions)207(374)581
Income before income taxes23861177
Income taxes131(53)184
Equity in losses of unconsolidated affiliates(5)(3)(2)
Net income102111(9)
Net income attributable to noncontrolling interests651
Net income attributable to common shareholders$96$106(10)

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. The variance in Net income attributable to common shareholders was unfavorable by $10 million primarily due to:

  • Unfavorable mark-to-market activity;

  • Higher labor, contracting and materials;

  • Lower capacity revenues; and

  • Unfavorable impacts of nuclear outages.

The unfavorable items were partially offset by:

  • Favorable net realized and unrealized NDT activity;

  • Favorable portfolio optimization activity; and

  • Favorable adjustment to estimated PJM net performance bonuses.

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

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

For the three months ended March 31, 2023 compared to 2022, Operating revenues by region were as follows:

Three Months Ended March 31,
20232022Variance% Change**(a)**
Mid-Atlantic$1,245$1,104$14112.8%
Midwest1,0321,197(165)(13.8)%
New York53536517046.6%
ERCOT169235(66)(28.1)%
Other Power Regions1,7911,927(136)(7.1)%
Total electric revenues4,7724,828(56)(1.2)%
Other1,8641,68418010.7%
Mark-to-market gains (losses)929(921)1,850
Total Operating revenues$7,565$5,591$1,97435.3%

(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)20232022Variance% Change
Nuclear Generation(a)
Mid-Atlantic13,18113,123580.4%
Midwest22,98623,462(476)(2.0)%
New York(b)6,2966,0132834.7%
Total Nuclear Generation42,46342,598(135)(0.3)%
Natural Gas, Oil, and Renewables
Mid-Atlantic722727(5)(0.7)%
Midwest339366(27)(7.4)%
ERCOT3,0992,9741254.2%
Other Power Regions2,9042,90220.1%
Total Natural Gas, Oil, and Renewables7,0646,969951.4%
Purchased Power
Mid-Atlantic4,0352,7721,26345.6%
Midwest423196227115.8%
ERCOT1,35173661583.6%
Other Power Regions9,91713,655(3,738)(27.4)%
Total Purchased Power15,72617,359(1,633)(9.4)%
Total Supply/Sales by Region
Mid-Atlantic17,93816,6221,3167.9%
Midwest23,74824,024(276)(1.1)%
New York6,2966,0132834.7%
ERCOT4,4503,71074019.9%
Other Power Regions12,82116,557(3,736)(22.6)%
Total Supply/Sales by Region65,25366,926(1,673)(2.5)%

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

(b)2022 values have been revised from those previously reported to correctly reflect our 82% undivided ownership interest in Nine Mile Point Unit 2.

Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants, which reflects ownership percentage of stations operated by us, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at its net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations of similarly titled measures or be more useful than the GAAP information provided elsewhere in this report.

Three Months Ended March 31,
20232022
Nuclear fleet capacity factor92.8%93.0%
Refueling outage days8676
Non-refueling outage days910

ZEC Prices. We are compensated through state programs for the carbon-free attributes for certain 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, 2023 and 2022.

Three Months Ended March 31,
State (Region)(a)20232022Variance% Change
New Jersey (Mid-Atlantic)$10.00$10.00$——%
Illinois (Midwest)12.0116.50(4.49)(27.2)%
New York (New York)21.3821.38——%

(a)The Salem, Clinton, Quad Cities, FitzPatrick, Ginna, and NMP plants are receiving payments under their respective state programs.

Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly and is based on the accepted CMC bid, less the sum of (a) monthly weighted average PJM Busbar price, (b) ComEd zone capacity price and (c) any federal tax credit or subsidy received and is subject to a customer protection cap ($30.30 per MWh for initial delivery period June 1, 2022 through May 31, 2023). If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. For the three months ended March 31, 2023, the average CMC price per MWh was $1.51. See Note 3 - Regulatory Matters of our 2022 Form 10-K for additional information on the Illinois CMC program.

Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a significant impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis within each region in either Operating revenues or Purchased power and fuel, depending on our net monthly position. The following table presents the average capacity reference 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, 2023 and 2022.

Three Months Ended March 31,
Location (Region)20232022Variance% Change
Eastern Mid-Atlantic Area Council (Mid-Atlantic)$97.86$165.73$(67.87)(41.0)%
ComEd (Midwest)68.96195.55(126.59)(64.7)%
Rest of State (New York)103.6785.1118.5621.8%
Southeast New England (Other)126.67154.37(27.70)(17.9)%

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)20232022Variance% Change
PJM West (Mid-Atlantic)$33.12$55.39$(22.27)(40.2)%
ComEd (Midwest)26.8040.25(13.45)(33.4)%
Central (New York)30.1665.95(35.79)(54.3)%
North (ERCOT)23.2537.04(13.79)(37.2)%
Southeast Massachusetts (Other)(a)51.84111.62(59.78)(53.6)%

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

For the three months ended March 31, 2023 compared to 2022, changes in Operating revenues by region were approximately as follows:

2023 vs. 2022
Variance% Change**(a)**Description
Mid-Atlantic$14112.8%• favorable wholesale load revenue of $225 primarily due to higher volumes • favorable adjustment to estimated PJM net performance bonuses of $5 due to generation performance against capacity requirements during December 2022 weather event; partially offset by • unfavorable settled economic hedges of ($90) due to settled prices relative to hedged prices
Midwest(165)(13.8)%• unfavorable settled economic hedges of ($145) due to settled prices relative to hedged prices • unfavorable net wholesale load and generation revenue of ($110) primarily due to lower nuclear generation and lower load volumes, partially offset by CMC program activity; partially offset by • favorable retail load revenue of $55 primarily due to higher contracted energy prices • favorable adjustment to estimated PJM performance bonuses of $33 due to generation performance against capacity requirements during December 2022 weather event
New York17046.6%• favorable settled economic hedges of $160 due to settled prices relative to hedged prices
ERCOT(66)(28.1)%• unfavorable settled economic hedges of ($110) due to settled prices relative to hedged prices; partially offset by • favorable wholesale load revenue of $30 primarily due to higher volumes partially offset by lower energy prices
Other Power Regions(136)(7.1)%• unfavorable settled economic hedges of ($285) due to settled prices relative to hedged prices; partially offset by • favorable retail load revenue of $95 primarily due to higher energy prices • favorable wholesale load revenue of $40 primarily due to higher energy prices partially offset by lower volume
Other18010.7%• favorable energy revenue of $125 primarily due to higher energy prices • favorable gas revenue of $55 primarily due to higher contracted gas prices
Mark-to-market(b)1,850• gains on economic hedging activities of $929 in 2023 compared to losses of ($921) in 2022
Total$1,97435.3%

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

(b)See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.

Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including supply sources by region, nuclear fleet capacity factor, capacity prices, and electricity prices.

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

For the three months ended March 31, 2023 compared to 2022, Purchased power and fuel expense by region were as follows:

Three Months Ended March 31,
20232022Variance% Change**(a)**
Mid-Atlantic$554$596$427.0%
Midwest3434126916.7%
New York27497(177)(182.5)%
ERCOT1171563925.0%
Other Power Regions1,5431,640975.9%
Total electric purchased power and fuel2,8312,901702.4%
Other1,7031,478(225)(15.2)%
Mark-to-market losses (gains)1,195(829)(2,024)
Total Purchased power and fuel$5,729$3,550$(2,179)(61.4)%

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

For the three months ended March 31, 2023 compared to 2022, changes in Purchased power and fuel expense by region were approximately as follows:

2023 vs. 2022
Variance% Change**(a)**Description
Mid-Atlantic$427.0%• favorable purchased power and net capacity impact of $80 primarily due to lower energy prices partially offset by lower capacity prices earned; partially offset by • unfavorable settlement of economic hedges of ($15) due to settled prices relative to hedged prices
Midwest6916.7%• favorable purchased power and net capacity impact of $85 primarily due to lower energy prices partially offset by lower capacity prices earned
New York(177)(182.5)%• unfavorable settlement of economic hedges of ($210) due to settled prices relative to hedged prices; partially offset by • favorable purchased power and net capacity impact of $35 primarily due to lower energy prices
ERCOT3925.0%• favorable fuel cost of $25 primarily due to lower gas prices
Other Power Regions975.9%• favorable purchased power and net capacity impact of $895 primarily due to lower energy prices and lower load • favorable fuel cost of $35 primarily due to lower gas prices; partially offset by • unfavorable settlement of economic hedges of ($820) due to settled prices relative to hedged prices
Other(225)(15.2)%• unfavorable net gas purchase costs and settlement of economic hedges of ($140) • unfavorable energy purchases of ($80) primarily due to higher energy prices
Mark-to-market(b)(2,024)• losses on economic hedging activities of ($1,195) in 2023 compared to gains of $829 in 2022
Total$(2,179)(61.4)%

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

(b)See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.

For the three months ended March 31, 2023 compared to 2022, changes in Operating and maintenance expense consisted of the following:

Three Months Ended March 31
Increase
Labor, contracting, and materials(a)$126
Nuclear refueling outage costs, including the co-owned Salem generating units45
Change in environmental liabilities16
Separation costs(b)11
Credit loss expense10
Decommissioning-related activities9
Other10
Total increase$227

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

(b)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.

Interest expense, net increased for the three months ended March 31, 2023 compared to the same period in 2022, primarily due to lower mark-to-market gains on the CR swaps and higher fees and interest incurred on short-term borrowings. See Note 17 — Debt and Credit Agreements of our 2022 Form 10-K for additional information on our CR credit facility and interest rate swaps and short-term borrowings.

Other, net was favorable for the three months ended March 31, 2023 compared to the same period in 2022, due to activity described in the table below:

Three Months Ended March 31,
20232022
Net unrealized gains (losses) on NDT funds(a)$18$(337)
Net realized gains on sale of NDT funds(a)16966
Interest and dividend income on NDT funds(a)2619
Contractual elimination of income tax benefit (expense)(b)67(72)
Non-service net periodic benefit credit(c)1418
Net realized and unrealized losses from equity investments(5)(20)
Other258
Total Other, net$314$(318)

(a)Unrealized gains, realized gains, and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement Units.

(b)Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement Units.

(c)Prior to separation, we were allocated our portion of pension and OPEB non-service credit (costs) from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 8 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional

Effective income tax rates were 55.0% and (86.9)% for the three months ended March 31, 2023 and 2022, respectively. The change in effective tax rate in 2023 is primarily due to the impacts of realized and unrealized NDT income on Income before income taxes. The effective tax rate in 2022 is primarily due to the impacts of unrealized NDT losses on Income before income taxes and one-time income tax adjustments. See Note 7 — 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 $5.9 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 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our debt and credit agreements.

Pursuant to the Separation Agreement between us and Exelon, we received a cash payment of $1.75 billion from Exelon on January 31, 2022. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 6 — 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, 2023, 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. See Liquidity and Capital Resources — NRC Minimum Funding Requirements of our 2022 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.

See Note 2 — Regulatory Matters and Note 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

The following table provides a summary of the change in cash flows from operating activities for the three months ended March 31, 2023 and 2022:

Three Months Ended March 31,
(Decrease) Increase in cash flows from operating activities20232022Change
Net income$102$111$(9)
Adjustments to reconcile net income to cash:
Collateral (posted) received, net(261)1,169(1,430)
Changes in working capital and other noncurrent assets and liabilities(a)(1,433)(595)(838)
Option premiums paid, net(23)(31)8
Pension and non-pension postretirement benefit contributions(10)(204)194
Total non-cash operating activities(b)691901(210)
Decrease in cash flows from operating activities$(934)$1,351$(2,285)

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

(b)See the Consolidated Statements of Cash Flows for details of non-cash operating activities, includes Depreciation, amortization, and accretion, Asset impairments, Gain on sales of assets and businesses, Deferred income taxes and amortization of ITCs, Net fair value changes related to derivatives, and Net realized and unrealized activity associated with NDTs and equity investments. See Note 15 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information on the Other non-cash operating activities line.

Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the three months ended March 31, 2023 and 2022 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 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral.

  • An increase in cash outflows for changes in working capital and other noncurrent assets and liabilities primarily relates to a decrease in Accounts payable and Accrued expenses for the three months ended March 31, 2023, primarily driven by higher prices and volumes at year end relates to the December 2022 weather event.

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, 2023 and 2022:

Three Months Ended March 31,
(Decrease) increase in cash flows from investing activities20232022Change
Capital expenditures$(660)$(410)$(250)
Proceeds from sales of assets and businesses2428(4)
Investment in NDT funds, net(53)(63)10
Collection of DPP, net92685373
Other investing activities(18)(4)(14)
Decrease in cash flows from investing activities$219$404$(185)

Significant investing cash flow impact for the three months ended March 31, 2023 and 2022 was as follows:

  • 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 2022 Form 10-K for information for additional information on projected capital expenditure spending.

  • Collection of DPP, net** increased due to more cash collections reinvested in the accounts receivable Facility. This was partially offset by the decrease in cash collections applied to DPP, due to an increase in the drawn Facility balance in 2023 compared to 2022. See Note 5 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the three months ended March 31, 2023 and 2022:

Three Months Ended March 31,
(Decrease) increase in cash flows from financing activities20232022Change
Long-term debt, net$1,323$(1,314)$2,637
Changes in short-term borrowings, net(454)(1,002)548
Dividends paid on common stock(93)(46)(47)
Repurchases of common stock(231)—(231)
Contributions from Exelon—1,750(1,750)
Other financing activities(22)(23)1
Increase in cash flows from financing activities$523$(635)$1,158

Significant financing cash flow impacts for the three months ended March 31, 2023 and 2022 were as follows:

  • Long-term debt, net,** varies due to debt issuances and redemptions each year. Refer to Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

  • Changes in short-term borrowings, net**, is driven by repayments on and issuances of notes due within one year of issuance. Refer to Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.

  • Refer to ITEM 5 — MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES in our 2022 Form 10-K for further information on dividend restrictions. See below for quarterly dividends declared.

  • Repurchases of common stock** is related to our share repurchase program that commenced in March 2023. See Note 13 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

  • Contribution from Exelon** is related to a cash contribution of $1.75 billion from Exelon on January 31, 2022, pursuant to the Separation Agreement. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation.

Dividends

Quarterly dividends declared by our Board of Directors during the three months ended March 31, 2023 and for the second quarter of 2023 were as follows:

PeriodDeclaration DateShareholder of Record DateDividend Payable DateCash per Share
First Quarter of 2023February 15, 2023February 27, 2023March 10, 2023$0.2820
Second Quarter of 2023April 25, 2023May 12, 2023June 9, 2023$0.2820

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, 2023, we have access to facilities with aggregate bank commitments of $5.9 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during the first quarter of 2023 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 2022 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, 2023, we would have been required to provide incremental collateral estimated to be approximately $2.4 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements. A loss of investment grade credit rating would have required a significant reduction in credit ratings from their current levels of BBB and Baa2 at S&P and Moody's, respectively, to BB+ and Ba1 or below. As of March 31, 2023, we had $3.9 billion of available capacity and $0.2 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding our available capacity and cash on hand, we could be required to access additional liquidity through the capital markets. See Note 9 — Derivative Financial Instruments and Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Pension and Other Postretirement Benefits

We consider various factors when making pension funding decisions, including actuarially-determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Pension Protection Act), and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are both subject to change, our estimated annual qualified pension planned contributions will be approximately $21 million in 2023. 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 2023 are approximately $10 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans is $17 million. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2022 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 2022 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 5 — 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 2022 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 10 — 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 9 — 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 did not change for the three months ended March 31, 2023.

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