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 (separation). Exelon completed the separation on February 1, 2022. We incurred separation costs of $18 million and $30 million for the three months ended September 30, 2023 and 2022, respectively, and $84 million and $99 million for the nine months ended September 30, 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 authority without expiration. Repurchases under this program commenced in March 2023. During the three and nine months ended September 30, 2023, we repurchased from the open market 2.3 million and 8.5 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $253 million and $756 million, respectively. See Note 14 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

Acquisition of Joint Ownership in South Texas Project

On November 1, 2023, we acquired NRG South Texas LP, which owns a 44% undivided ownership interest in the jointly owned South Texas Project Nuclear Generating Station (STP), a 2,645-megawatt, dual-unit nuclear plant located in Bay City, Texas, for a cash purchase price of $1.75 billion. This acquisition is complementary to and aligned strategically with our existing clean energy business operations. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined notes to the Consolidated Financial Statements for additional information on this acquisition.

Revenue Recognized for Illinois ZECs Delivered in Prior Planning Years

Our Clinton and Quad Cities units contract with certain utilities in Illinois which requires delivery of all ZECs produced during each planning year (June 1 to May 31), with total compensation limited by an annual cap for each planning year designed to limit the cost of ZECs to each utility's customers. ZECs delivered that, if paid, would result in the annual cap being exceeded may be paid in subsequent years at the vintage year price as long as the payments would not exceed the annual cap in the year paid. In each planning year since the program commenced on June 1, 2017, we delivered ZECs to the utilities in excess of the annual compensation cap.

The ZEC price and annual compensation cap effective for each planning year are administratively determined by the IPA. For the June 1, 2023 to May 31, 2024 planning year, the ZEC price has been established at $0.30 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year will not exceed the annual cap, providing capacity to compensate for ZECs delivered in prior planning years in excess of the compensation cap. During the second quarter of 2023, we recognized $218 million of revenue as a

receivable for ZECs delivered in prior planning years, with payment expected in the third quarter of 2024. As of September 30, 2023, this receivable is included within Customer accounts receivable, net in the Consolidated Balance Sheets.

Other Key Business Drivers

Russia and Ukraine Conflict

We are closely monitoring developments of the Russia and Ukraine conflict including United States, United Kingdom, European Union, and Canadian sanctions 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. To-date, our nuclear fuel deliveries have not been affected by the Russia and Ukraine conflict. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel and generally have enough nuclear fuel to support all our refueling needs for multiple years regardless of sanctions. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. We are taking this affirmative action by working with our diverse set of suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term and provide the necessary fuel to bridge potential Russian supply disruption through 2028, which is the date multiple suppliers are expected to have incremental additional 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.

Critical Accounting Policies and Estimates

Management makes a number of significant estimates, assumptions, and judgements in the preparation of our financial statements. At September 30, 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 (Loss) Attributable to Common Shareholders for the three and nine months ended September 30, 2023 compared to the same periods in 2022. For additional information regarding the financial results for the three and nine months ended September 30, 2023 and 2022 see the discussions of Results of Operations below.

			Three Months Ended September 30,												Favorable Variance						Nine Months Ended September 30,												Favorable Variance
			2023						2022									2023						2022
GAAP Net Income (Loss) Attributable to Common Shareholders			$	731					$	(188)					$	919					$	1,660					$	(194)					$	1,854

Adjusted EBITDA (non-GAAP). In analyzing and planning for our business, we supplement our use of GAAP Net Income (Loss) Attributable to Common Shareholders with Adjusted EBITDA (non-GAAP) as a performance measure. Adjusted EBITDA (non-GAAP) reflects an additional way of viewing our business that, when viewed with our GAAP results and the accompanying reconciliation to GAAP Net Income (Loss) Attributable to Common Shareholders included in the table below, may provide a more complete understanding of factors and trends affecting our core 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.

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The following table provides a reconciliation between Net Income (Loss) Attributable to Common Shareholders as determined in accordance with GAAP and Adjusted EBITDA (non-GAAP) for the three and nine months ended September 30, 2023 compared to the same periods in 2022.

			Three Months Ended September 30,												Nine Months Ended September 30,
			2023						2022						2023						2022
Net Income (Loss) Attributable to Common Shareholders			$	731					$	(188)					$	1,660					$	(194)
Income Taxes(a)			209						(149)						682						(472)
Depreciation and Amortization			266						262						808						818
Interest Expense, Net			82						75						292						187
Unrealized (Gain) Loss on Fair Value Adjustments(b)			(215)						550						(344)						645
Asset Impairments			71						—						71						—
Plant Retirements and Divestitures			—						5						(28)						(3)
Decommissioning-Related Activities(c)			79						88						(277)						1,126
Pension & OPEB Non-Service Credits			(14)						(27)						(41)						(85)
Separation Costs(d)			18						30						84						99
Acquisition-Related Costs			—						—						2						—
ERP System Implementation Costs(e)			5						5						20						16
Change in Environmental Liabilities			13						3						29						12
Prior Merger Commitment(f)			—						(50)						—						(50)
Noncontrolling Interests(g)			(46)						(12)						(70)						(37)
Adjusted EBITDA (non-GAAP)			$	1,199					$	592					$	2,888					$	2,062

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(a)Includes amounts contractually owed to Exelon under the TMA reflected in Other, net.

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

(c)Reflects all gains and losses associated with NDTs, ARO accretion, ARO remeasurement, and any earnings neutral 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 implementation.

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

(g)Represents elimination from results for the noncontrolling interests related to certain adjustments.

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Results of Operations

			Three Months Ended September 30,												Favorable (Unfavorable) Variance						Nine Months Ended September 30,												Favorable (Unfavorable) Variance
			2023						2022									2023						2022
Operating revenues			$	6,111					$	6,051					$	60					$	19,122					$	17,107					$	2,015
Operating expenses
Purchased power and fuel			3,367						4,695						1,328						11,983						11,754						(229)
Operating and maintenance			1,353						989						(364)						4,263						3,466						(797)
Depreciation and amortization			266						262						(4)						808						818						10
Taxes other than income taxes			148						145						(3)						419						415						(4)
Total operating expenses			5,134						6,091						957						17,473						16,453						(1,020)
(Loss) gain on sales of assets and businesses			—						(1)						1						28						13						(15)
Operating income (loss)			977						(41)						1,018						1,677						667						1,010
Other income and (deductions)
Interest expense, net			(82)						(75)						(7)						(292)						(187)						(105)
Other, net			—						(196)						196						919						(1,169)						2,088
Total other income and (deductions)			(82)						(271)						189						627						(1,356)						1,983
Income (loss) before income taxes			895						(312)						1,207						2,304						(689)						2,993
Income taxes			205						(123)						(328)						677						(504)						(1,181)
Equity in losses of unconsolidated affiliates			—						(4)						4						(11)						(10)						(1)
Net income (loss)			690						(193)						883						1,616						(195)						1,811
Net loss attributable to noncontrolling interests			(41)						(5)						(36)						(44)						(1)						(43)
Net income (loss) attributable to common shareholders			$	731					$	(188)					$	919					$	1,660					$	(194)					1,854

Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. The variance in Net income (loss) attributable to common shareholders was favorable by $919 million primarily due to:

• Favorable market and portfolio conditions primarily driven by higher realized margins on load contracts and generation-to-load optimization;

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

• Favorable net realized and unrealized NDT activity; and

• Favorable impact of net realized and unrealized equity investment activity.

The favorable items were partially offset by:

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

• Higher labor, contracting and materials; and

• Lower ZEC revenues primarily driven by lower Illinois ZEC prices in the current planning year.

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Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. The variance in Net income (loss) attributable to common shareholders was favorable by $1,854 million primarily due to:

• Favorable net realized and unrealized NDT activity;

• Favorable market and portfolio conditions primarily driven by higher realized margins on load contracts and generation-to-load optimization;

• Unrealized gains resulting from an investment that became a publicly traded company in the second quarter of 2023;

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

• Higher ZEC revenues primarily driven by revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years.

The favorable items were partially offset by:

• Higher labor, contracting and materials;

• Lower capacity revenues;

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

• Unfavorable impacts of nuclear outages; and

• Higher interest expense.

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

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

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For the three and nine months ended September 30, 2023 compared to 2022, Operating revenues by region were as follows:

			Three Months Ended September 30,																								Nine Months Ended September 30,
			2023						2022						Variance						% Change**(a)**						2023						2022						Variance						% Change**(a)**
Mid-Atlantic			$	1,411					$	1,659					$	(248)					(14.9)		%				$	3,854					$	3,967					$	(113)					(2.8)		%
Midwest			1,117						1,047						70						6.7		%				3,479						3,345						134						4.0		%
New York			512						423						89						21.0		%				1,518						1,178						340						28.9		%
ERCOT			559						490						69						14.1		%				1,056						1,210						(154)						(12.7)		%
Other Power Regions			1,592						1,936						(344)						(17.8)		%				4,495						5,189						(694)						(13.4)		%
Total electric revenues			5,191						5,555						(364)						(6.6)		%				14,402						14,889						(487)						(3.3)		%
Other			743						1,177						(434)						(36.9)		%				3,403						4,117						(714)						(17.3)		%
Mark-to-market gains (losses)			177						(681)						858												1,317						(1,899)						3,216
Total Operating revenues			$	6,111					$	6,051					$	60					1.0		%				$	19,122					$	17,107					$	2,015					11.8		%

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

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Sales and Supply Sources. Our sales and supply sources by region are summarized below:

			Three Months Ended September 30,																								Nine Months Ended September 30,
Supply Source (GWhs)			2023						2022						Variance						% Change						2023						2022						Variance						% Change
Nuclear Generation(a)
Mid-Atlantic			13,654						13,540						114						0.8		%				39,672						39,272						400						1.0		%
Midwest			24,023						24,275						(252)						(1.0)		%				69,975						71,079						(1,104)						(1.6)		%
New York			6,448						5,979						469						7.8		%				18,837						18,563						274						1.5		%
Total Nuclear Generation			44,125						43,794						331						0.8		%				128,484						128,914						(430)						(0.3)		%
Natural Gas, Oil, and Renewables
Mid-Atlantic			361						230						131						57.0		%				1,466						1,573						(107)						(6.8)		%
Midwest			155						126						29						23.0		%				715						774						(59)						(7.6)		%
ERCOT			5,146						4,987						159						3.2		%				12,286						10,873						1,413						13.0		%
Other Power Regions			1,929						2,401						(472)						(19.7)		%				6,544						7,179						(635)						(8.8)		%
Total Natural Gas, Oil, and Renewables			7,591						7,744						(153)						(2.0)		%				21,011						20,399						612						3.0		%
Purchased Power
Mid-Atlantic			6,166						6,508						(342)						(5.3)		%				13,615						12,164						1,451						11.9		%
Midwest			104						74						30						40.5		%				726						425						301						70.8		%
ERCOT			1,612						705						907						128.7		%				4,561						2,855						1,706						59.8		%
Other Power Regions			13,221						13,869						(648)						(4.7)		%				32,875						39,964						(7,089)						(17.7)		%
Total Purchased Power			21,103						21,156						(53)						(0.3)		%				51,777						55,408						(3,631)						(6.6)		%
Total Supply/Sales by Region
Mid-Atlantic			20,181						20,278						(97)						(0.5)		%				54,753						53,009						1,744						3.3		%
Midwest			24,282						24,475						(193)						(0.8)		%				71,416						72,278						(862)						(1.2)		%
New York			6,448						5,979						469						7.8		%				18,837						18,563						274						1.5		%
ERCOT			6,758						5,692						1,066						18.7		%				16,847						13,728						3,119						22.7		%
Other Power Regions			15,150						16,270						(1,120)						(6.9)		%				39,419						47,143						(7,724)						(16.4)		%
Total Supply/Sales by Region			72,819						72,694						125						0.2		%				201,272						204,721						(3,449)						(1.7)		%

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(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.

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.

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			Three Months Ended September 30,												Nine Months Ended September 30,
			2023						2022						2023						2022
Nuclear fleet capacity factor			97.2		%				96.4		%				94.1		%				94.5		%
Refueling outage days			20						5						200						147
Non-refueling outage days			10						26						44						51

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 and nine months ended September 30, 2023 and 2022.

			Three Months Ended September 30,																								Nine Months Ended September 30,
State (Region)(a)			2023						2022						Variance						% Change						2023						2022						Variance						% Change
New Jersey (Mid-Atlantic)(b)			$	10.00					$	9.88					$	0.12					1.2		%				$	9.93					$	9.95					$	(0.02)					(0.2)		%
Illinois (Midwest)(c)			0.30						12.01						(11.71)						(97.5)		%				6.81						14.50						(7.69)						(53.0)		%
New York (New York)			18.27						21.38						(3.11)						(14.5)		%				19.31						21.38						(2.07)						(9.7)		%

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

(c)See Note 4 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information on the Illinois ZEC program.

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 $2.12 and ($51.70) for the three months ended September 30, 2023 and 2022, respectively and $3.54 and ($51.85) for the nine months ended September 30, 2023 and 2022, respectively. 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 and nine months ended September 30, 2023 and 2022.

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			Three Months Ended September 30,																								Nine Months Ended September 30,
Location (Region)			2023						2022						Variance						% Change						2023						2022						Variance						% Change
Eastern Mid-Atlantic Area Council (Mid-Atlantic)			$	49.49					$	97.86					$	(48.37)					(49.4)		%				$	76.36					$	135.57					$	(59.21)					(43.7)		%
ComEd (Midwest)			34.13						68.96						(34.83)						(50.5)		%				53.48						139.29						(85.81)						(61.6)		%
Rest of State (New York)			199.89						108.22						91.67						84.7		%				147.48						89.67						57.81						64.5		%
Southeast New England (Other)			66.67						126.67						(60.00)						(47.4)		%				100.00						142.06						(42.06)						(29.6)		%

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 September 30,																								Nine Months Ended September 30,
Location (Region)			2023						2022						Variance						% Change						2023						2022						Variance						% Change
PJM West (Mid-Atlantic)			$	33.31					$	90.43					$	(57.12)					(63.2)		%				$	31.95					$	74.33					$	(42.38)					(57.0)		%
ComEd (Midwest)			30.85						81.99						(51.14)						(62.4)		%				26.75						62.90						(36.15)						(57.5)		%
Central (New York)			29.58						74.96						(45.38)						(60.5)		%				26.85						60.89						(34.04)						(55.9)		%
North (ERCOT)			129.60						97.58						32.02						32.8		%				64.41						68.47						(4.06)						(5.9)		%
Southeast Massachusetts (Other)(a)			33.45						86.27						(52.82)						(61.2)		%				38.15						89.01						(50.86)						(57.1)		%

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

For the three and nine months ended September 30, 2023 compared to 2022, changes in Operating revenues by region were approximately as follows:

			Three Months Ended September 30																		Nine Months Ended September 30
			Variance						% Change**(a)**						Description						Variance						% Change**(a)**						Description
Mid-Atlantic			(248)						(14.9)		%				• unfavorable settled economic hedges of ($200) due to settled prices relative to hedged prices • unfavorable retail load revenue of ($50) primarily due to lower contracted energy prices						(113)						(2.8)		%				• unfavorable settled economic hedges of ($380) due to settled prices relative to hedged prices; partially offset by • favorable wholesale load revenue of $285 primarily due to higher contracted energy prices and higher volumes

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			Three Months Ended September 30																		Nine Months Ended September 30
			Variance						% Change**(a)**						Description						Variance						% Change**(a)**						Description
Midwest			70						6.7		%				• favorable net generation revenue and CMC activity of $175 primarily due to our generation volume and realized prices relative to our purchased power to supply load • favorable settled economic hedges of $55 due to settled prices relative to hedged prices; partially offset by • unfavorable wholesale load revenue of ($90) primarily due to lower volumes • unfavorable ZEC revenue of ($55) primarily due to a decrease in the ZEC price in current planning year • unfavorable retail load revenue of ($30) primarily due to lower contracted energy prices partially offset by higher load volumes						134						4.0		%				• favorable ZEC revenue of $140 primarily due to revenue recognized for Illinois ZECs delivered in prior planning years partially offset by a decrease in the ZEC price in current planning year • favorable settled economic hedges of $90 due to settled prices relative to hedged prices • favorable retail load revenue of $25 primarily due to higher load volumes, partially offset by lower contracted energy prices; partially offset by • unfavorable net generation and wholesale load revenue of ($175) primarily due to lower nuclear generation and lower load volumes, partially offset by CMC program activity and net capacity revenue
New York			89						21.0		%				• favorable settled economic hedges of $100 due to settled prices relative to hedged prices • favorable retail load revenue of $35 primarily due to higher contracted energy prices; partially offset by • unfavorable net generation revenue of ($40) primarily due to lower energy prices partially offset by higher nuclear generation						340						28.9		%				• favorable settled economic hedges of $360 due to settled prices relative to hedged prices • favorable retail load revenue of $80 primarily due to higher contracted energy prices; partially offset by • unfavorable net generation revenue of ($110) primarily due to lower energy prices
ERCOT			69						14.1		%				• favorable wholesale load revenue of $180 primarily due to higher volumes; partially offset by • unfavorable settled economic hedges of ($130) due to settled prices relative to hedged prices						(154)						(12.7)		%				• unfavorable settled economic hedges of ($460) due to settled prices relative to hedged prices; partially offset by • favorable wholesale load revenue of $295 primarily due to higher volumes

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			Three Months Ended September 30																		Nine Months Ended September 30
			Variance						% Change**(a)**						Description						Variance						% Change**(a)**						Description
Other Power Regions			(344)						(17.8)		%				• unfavorable settled economic hedges of ($270) due to settled prices relative to hedged prices • unfavorable wholesale load revenue of ($100) primarily due to lower volumes; partially offset by • favorable retail load revenue of $30 primarily due to higher contracted energy prices						(694)						(13.4)		%				• unfavorable settled economic hedges of ($730) due to settled prices relative to hedged prices • unfavorable wholesale load revenue of ($140) primarily due to lower volumes; partially offset by • favorable retail load revenue of $170 primarily due to higher contracted energy prices
Other			(434)						(36.9)		%				• unfavorable gas revenue, including settled economic hedges, of ($460) primarily due to lower gas prices; partially offset by • favorable energy revenue of $35 primarily due to higher energy prices						(714)						(17.3)		%				• unfavorable gas revenue, including settled economic hedges, of ($785) primarily due to lower gas prices; partially offset by • favorable energy revenue of $65 primarily due to higher energy prices
Mark-to-market(b)			858												• gains on economic hedging activities of $177 in 2023 compared to losses of ($681) in 2022						3,216												• gains on economic hedging activities of $1,317 in 2023 compared to losses of ($1,899) in 2022
Total			$	60					1.0		%										$	2,015					11.8		%

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(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.

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.

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For the three and nine months ended September 30, 2023 compared to 2022, Purchased power and fuel expense by region were as follows:

			Three Months Ended September 30,																								Nine Months Ended September 30,
			2023						2022						Variance						% Change**(a)**						2023						2022						Variance						% Change**(a)**
Mid-Atlantic			$	667					$	1,104					$	437					39.6		%				$	1,696					$	2,355					$	659					28.0		%
Midwest			339						475						136						28.6		%				1,038						1,335						297						22.2		%
New York			195						156						(39)						(25.0)		%				621						351						(270)						(76.9)		%
ERCOT			352						424						72						17.0		%				633						975						342						35.1		%
Other Power Regions			1,161						1,679						518						30.9		%				3,594						4,479						885						19.8		%
Total electric purchased power and fuel			2,714						3,838						1,124						29.3		%				7,582						9,495						1,913						20.1		%
Other			613						1,014						401						39.5		%				2,947						3,587						640						17.8		%
Mark-to-market losses (gains)			40						(157)						(197)												1,454						(1,328)						(2,782)
Total Purchased power and fuel			$	3,367					$	4,695					$	1,328					28.3		%				$	11,983					$	11,754					$	(229)					(1.9)		%

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

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For the three and nine months ended September 30, 2023 compared to 2022, changes in Purchased power and fuel expense by region were approximately as follows:

			Three Months Ended September 30																		Nine Months Ended September 30
			Variance						% Change**(a)**						Description						Variance						% Change**(a)**						Description
Mid-Atlantic			$	437					39.6		%				• favorable purchased power and net capacity impact of $490 primarily due to lower energy prices and higher nuclear generation partially offset by lower capacity prices earned; partially offset by • unfavorable environmental products activity of ($75) primarily due to higher REC prices						$	659					28.0		%				• favorable purchased power and net capacity impact of $815 primarily due to lower energy prices partially offset by lower capacity prices earned; partially offset by • unfavorable environmental products activity of ($115) primarily due to higher load served and higher REC prices • unfavorable settlement of economic hedges of ($45) due to settled prices relative to hedged prices
Midwest			136						28.6		%				• favorable cost associated with power delivery and net capacity impact of $135 primarily due to lower energy prices partially offset by lower capacity prices earned						297						22.2		%				• favorable cost associated with power delivery and net capacity impact of $325 primarily due to lower energy prices partially offset by lower capacity prices earned
New York			(39)						(25.0)		%				• unfavorable settlement of economic hedges of ($35) due to settled prices relative to hedged prices						(270)						(76.9)		%				• unfavorable settlement of economic hedges of ($360) due to settled prices relative to hedged prices; partially offset by • favorable cost associated with power delivery and net capacity impact of $95 primarily due to lower energy prices and higher capacity prices earned
ERCOT			72						17.0		%				• favorable settlement of economic hedges of $150 due to settled prices relative to hedged prices • favorable fuel cost of $35 primarily due to lower gas prices; partially offset by • unfavorable purchased power of ($105) primarily due to higher energy prices and higher load served						342						35.1		%				• favorable settlement of economic hedges of $210 due to settled prices relative to hedged prices • favorable fuel cost of $75 primarily due to lower gas prices partially offset by higher generation • favorable purchased power of $70 primarily due to lower energy prices and higher generation partially offset by higher load served

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			Three Months Ended September 30																		Nine Months Ended September 30
			Variance						% Change**(a)**						Description						Variance						% Change**(a)**						Description
Other Power Regions			518						30.9		%				• favorable purchased power and fuel of $920 primarily due to lower energy prices and lower load served; partially offset by • unfavorable settlement of economic hedges of ($405) due to settled prices relative to hedged prices						885						19.8		%				• favorable purchased power and fuel of $2,505 primarily due to lower energy prices and lower load served; partially offset by • unfavorable settlement of economic hedges of ($1,600) due to settled prices relative to hedged prices
Other			401						39.5		%				• favorable net gas purchase costs and settlement of economic hedges of $430 primarily due to lower gas prices; partially offset by • unfavorable energy purchases of ($55) primarily due to higher energy prices						640						17.8		%				• favorable net gas purchase costs and settlement of economic hedges of $620 primarily due to lower gas prices • favorable fair value adjustment related to gas imbalances of $50; partially offset by • unfavorable energy purchases of ($30) primarily due to higher energy prices
Mark-to-market(b)			(197)												• losses on economic hedging activities of ($40) in 2023 compared to gains of $157 in 2022						(2,782)												• losses on economic hedging activities of ($1,454) in 2023 compared to gains of $1,328 in 2022
Total			$	1,328					28.3		%										$	(229)					(1.9)		%

.__________

(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.

For the three and nine months ended September 30, 2023 compared to 2022, changes in Operating and maintenance expense consisted of the following:

			Three Months Ended September 30						Nine Months Ended September 30
			(Decrease) Increase						(Decrease) Increase
Labor, contracting, and materials(a)			$	93					$	309
Decommissioning-related activities(b)			155						171
Nuclear refueling outage costs, including the co-owned Salem generating units			15						109
Asset impairments			71						71
Prior merger commitment(c)			50						50
Insurance, IT & Travel			18						46
Credit loss expense			(3)						24
Other			(35)						17
Total increase			$	364					$	797

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

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(b)Primarily reflects a decreased benefit related to the annual nuclear ARO update for non-regulatory units.

(c)Reflects absence of a prior year gain recognized as a reversal of charge related to a 2012 merger commitment. See Note 13 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Interest expense, net increased for the nine months ended September 30, 2023 compared to the same period in 2022, primarily due to the issuance of senior notes and tax exempt bonds, increased fees and interest on short term borrowings, and changes in the 13-week Treasury rate for our SNF obligation. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our senior notes and tax-exempt bonds. See Note 17 — Debt and Credit Agreements of our 2022 Form 10-K for additional information on our short-term borrowings. See Note 19 — Commitments and Contingencies of our 2022 Form 10-K for additional information on our SNF obligation.

Other, net was favorable for the three and nine months ended September 30, 2023 compared to the same period in 2022, due to activity described in the table below:

			Other, net
			Three Months Ended September 30,												Nine Months Ended September 30,
			(Unfavorable) Favorable												(Unfavorable) Favorable
			2023						2022						2023						2022
Decommissioning-related activities(a)			$	(109)					$	(273)					$	328					$	(1,246)
Non-service net periodic benefit credit(b)			14						27						41						79
Net realized and unrealized gains (losses) from equity investments(c)			76						(2)						490						(27)
Return to provision adjustment(d)			(5)						26						(5)						(32)
Other(e)			24						26						65						57
Other, net			$	—					$	(196)					$	919					$	(1,169)

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(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)Prior to separation, we were allocated our portion of pension and OPEB non-service credits (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 9 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.

(c)For 2023, includes unrealized gain resulting from equity investment that became publicly traded in the second quarter of 2023 and now has a readily determinable fair value (and no longer is accounted for as an equity method investment due to lack of significant influence). We recorded the fair value of this investment in Investments on the Consolidated Balance Sheets based on quoted market price of the stock. See Note 12 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information.

(d)This reflects amounts contractually owed to Exelon under the TMA, which is offset in Income taxes.

(e)Includes amounts we billed Exelon for services pursuant to the TSA. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information.

Effective income tax rates were 22.9% and 39.4% for the three months ended September 30, 2023 and 2022, respectively, and 29.4% and 73.1% for the nine months ended September 30, 2023 and 2022, respectively. We do not expect the effective tax rate to deviate from the statutory tax rate with the exception of realized and unrealized gains and losses of the nuclear decommissioning trust funds. In 2022, the rate was also impacted by one-time adjustments. See Note 8 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Net income attributable to noncontrolling interests primarily relates to CRP for the three and nine months ended September 30, 2023 and 2022.

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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 11 — 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 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 September 30, 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 3 — Regulatory Matters and Note 13 — 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 nine months ended September 30, 2023 and 2022:

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			Nine Months Ended September 30,
Cash flows from operating activities			2023						2022						Change
Net income (loss)			$	1,616					$	(195)					$	1,811
Adjustments to reconcile net income (loss) to cash:
Changes in working capital and other noncurrent assets and liabilities(a)			(5,109)						(2,899)						(2,210)
Collateral (posted) received, net			(222)						766						(988)
Option premiums paid, net			(36)						(163)						127
Pension and non-pension postretirement benefit contributions			(46)						(229)						183
Total non-cash operating activities(b)			1,678						2,789						(1,111)
Net cash flows (used in) provided by operating activities			$	(2,119)					$	69					$	(2,188)

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(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, 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. In addition, significant operating cash flow impacts for the nine months ended September 30, 2023 and 2022 were as follows:

• A net 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, primarily driven by lower gas prices and a decrease in ComEd CMC program activity for the current year. This was partially offset by a decrease in Accounts receivable, mainly driven by higher contracted prices and volumes at year end 2022 including the impact of the December 2022 weather event. Additionally, there was a decrease in Other assets and liabilities, primarily driven by an increase in cash collections applied to DPP due to a decrease in the drawn Facility balance in 2023 compared to 2022. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on accounts receivable.

• 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.

• Decrease in cash outflows for pension and non-pension postretirement benefit contributions is primarily due to our annual qualified pension contribution of $21 million and $192 million made in July 2023 and February 2022, respectively. See Note 9 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and non-pension postretirement benefit plans.

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Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2023 and 2022:

			Nine Months Ended September 30,
Cash flows from investing activities			2023						2022						Change
Collection of DPP, net			$	4,058					$	3,095					$	963
Investment in NDT funds, net			(153)						(178)						25
Proceeds from sales of assets and businesses			24						41						(17)
Capital expenditures			(1,735)						(1,090)						(645)
Other investing activities			(15)						3						(18)
Net cash flows provided by investing activities			$	2,179					$	1,871					$	308

Significant investing cash flow impacts for the nine months ended September 30, 2023 and 2022 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 2023 compared to 2022. In addition, more cash collections were reinvested in the Facility in 2023. 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 2022 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 nine months ended September 30, 2023 and 2022:

			Nine Months Ended September 30,
Cash flows from financing activities			2023						2022						Change
Long-term debt, net			$	3,042					$	(1,392)					$	4,434
Changes in short-term borrowings, net			(632)						(1,389)						757
Dividends paid on common stock			(277)						(139)						(138)
Repurchases of common stock			(750)						—						(750)
Contributions from Exelon			—						1,750						(1,750)
Other financing activities			6						(43)						49
Net cash flows provided by (used in) financing activities			$	1,389					$	(1,213)					$	2,602

Significant financing cash flow impacts for the nine months ended September 30, 2023 and 2022 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.

• 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.

• 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.

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• 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.

• 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 nine months ended September 30, 2023 and for the fourth quarter of 2023 were as follows:

Period						Declaration Date						Shareholder of Record Date						Dividend Payable Date						Cash per Share
First Quarter of 2023						February 15, 2023						February 27, 2023						March 10, 2023						$	0.282
Second Quarter of 2023						April 25, 2023						May 12, 2023						June 9, 2023						$	0.282
Third Quarter of 2023						August 1, 2023						August 14, 2023						September 8, 2023						$	0.282
Fourth Quarter of 2023						November 1, 2023						November 17, 2023						December 8, 2023						$	0.282

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 September 30, 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 third 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 September 30, 2023, 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 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 September 30, 2023, we had $4.1 billion of available capacity and $1.9 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 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 of 2006 (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

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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 annual qualified pension contribution was made in July 2023 for $21 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 2023 are approximately $10 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans, is $30 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

On November 1, 2023, we acquired NRG South Texas LP for a cash purchase price of $1.75 billion. We used the proceeds from the third quarter 2023 senior note issuances in the aggregate principal amount of $1.4 billion, together with available cash balances, to fund the acquisition. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 11 — Debt and Credit Agreements of the Combined notes to the Consolidated Financial Statements for additional information on this acquisition.

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 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 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 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.

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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 Baa2, respectively, as of September 30, 2023 and have not changed during the nine months ended September 30, 2023.