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.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth our GAAP consolidated Net (loss) income for the three and nine months ended September 30, 2022 compared to the same period in 2021. For additional information regarding the financial results for the three and nine months ended September 30, 2022 and 2021 see the discussions of Results of Operations below.


	Three Months Ended September 30,				Favorable (Unfavorable) Variance			Nine Months Ended September 30,					Favorable (Unfavorable) Variance
	2022		2021				2022			2021
GAAP Net (loss) income	$	(188)	$	607	$	(795)		$	(194)		$	(247)	$	53

Adjusted EBITDA (non-GAAP). In analyzing and planning for our business, we supplement our use of GAAP net income 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 included in the table below, may provide a more complete understanding of factors and trends affecting our business. Adjusted EBITDA (non-GAAP) should not be relied upon to the exclusion of GAAP financial measures and is, by definition, an incomplete understanding of our business, and must be considered in conjunction with GAAP measures. In addition, Adjusted EBITDA (non-GAAP) is neither a standardized financial measure, nor a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

The following table provides a reconciliation between Net (loss) income attributable to common shareholders as determined in accordance with GAAP and Adjusted EBITDA (non-GAAP) for the three and nine months ended September 30, 2022 compared to the same period in 2021.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021

Net (Loss) Income Attributable to Common Shareholders	$	(188)	$	607	$	(194)	$	(247)
Income Taxes(a)	(149)		177		(472)		108
Depreciation and Amortization(b)	262		866		818		2,735
Interest Expense, Net	75		77		187		225
Unrealized Loss (Gain) on Fair Value Adjustments(c)	550		(614)		645		(1,191)
Asset Impairments(d)	—		45		—		537
Plant Retirements and Divestitures(e)	5		(62)		(3)		(15)
Decommissioning-Related Activities(f)	88		(130)		1,126		(1,014)
Pension & OPEB Non-Service Credits	(27)		(11)		(85)		(36)
Separation Costs(g)	30		16		99		25
COVID-19 Direct Costs(h)	—		5		—		24
Acquisition-Related Costs(i)	—		11		—		21
ERP System Implementation Costs(j)	5		5		16		10
Change in Environmental Liabilities	3		5		12		7
Cost Management Program	—		4		—		9
Prior Merger Commitment(k)	(50)		—		(50)		—
Noncontrolling Interests(l)	(12)		(34)		(37)		(40)

Adjusted EBITDA (non-GAAP)	$	592	$	967	$	2,062	$	1,158

(a)In 2022, includes amounts contractually owed to Exelon under the tax matters agreement reflected in Other, net.

(b)In 2021, includes the accelerated depreciation associated with early plant retirements.

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

(d)Reflects an impairment of a wind project in the third quarter of 2021, and nine months ended, September 30, 2021 also includes an impairment in the New England asset group, and an impairment recorded as a result of the sale of the Albany Green Energy biomass facility.

(e)In 2021, primarily reflects accelerated nuclear fuel amortization for Byron and Dresden, partially offset by a gain on sale of our solar business which occurred in the first quarter of 2021 and a reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden.

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

(g)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.

(h)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.

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

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

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

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

Results of Operations


	Three Months Ended September 30,				Favorable (Unfavorable) Variance			Nine Months Ended September 30,					Favorable (Unfavorable) Variance
	2022		2021				2022			2021
Operating revenues	$	6,051	$	4,406	$	1,645		$	17,107		$	14,117	$	2,990
Operating expenses
Purchased power and fuel	4,695		1,546		(3,149)			11,754			8,103		(3,651)
Operating and maintenance	989		938		(51)			3,466			3,413		(53)
Depreciation and amortization	262		866		604			818			2,735		1,917
Taxes other than income taxes	145		115		(30)			415			354		(61)
Total operating expenses	6,091		3,465		(2,626)			16,453			14,605		(1,848)

(Loss) gain on sales of assets and businesses	(1)		65		(66)			13			144		(157)


Operating (loss) income	(41)		1,006		(1,047)			667			(344)		1,011
Other income and (deductions)
Interest expense, net	(75)		(77)		2			(187)			(225)		38
Other, net	(196)		(115)		(81)			(1,169)			561		(1,730)
Total other income and (deductions)	(271)		(192)		(79)			(1,356)			336		(1,692)
(Loss) income before income taxes	(312)		814		(1,126)			(689)			(8)		(681)
Income taxes	(123)		177		300			(504)			108		(612)
Equity in losses of unconsolidated affiliates	(4)		(4)		—			(10)			(6)		(4)
Net (loss) income	(193)		633		(826)			(195)			(122)		(73)
Net (loss) income attributable to noncontrolling interests	(5)		26		(31)			(1)			125		(126)
Net (loss) income attributable to common shareholders	$	(188)	$	607	$	(795)		$	(194)		$	(247)	53

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021. Net (loss) income attributable to common shareholders was unfavorable by $795 million primarily due to:

Unfavorable mark-to-market activity;
Unfavorable net realized and unrealized NDT activity;
Higher labor, contracting and materials;
Lower capacity revenues; and
Unfavorable portfolio optimization activity

The unfavorable items were partially offset by:

The absence of accelerated depreciation and amortization associated with our previous decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021 and the absence of the reversal of charges recorded in the third quarter of 2021 associated with the reversal of the previous decision;
Impact of our annual update to the nuclear ARO for Non-Regulatory Agreement Units;
Favorable impact of net realized and unrealized CTV investment activity; and
The reversal of a charge related to a 2012 prior merger commitment

Nine months ended September 30, 2022 Compared to Nine months ended September 30, 2021. Net loss attributable to common shareholders was favorable by $53 million primarily due to:

The absence of accelerated depreciation and amortization associated with our previous decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021, the absence of the reversal of charges recorded in the third quarter of 2021 associated with the reversal of the previous decision, and our decision in the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024;
The absence of impacts from the February 2021 extreme cold weather event;
The absence of impairments of the New England asset group, the Albany Green Energy biomass facility, and a wind project;
Higher realized energy prices;
Impact of our annual update to the nuclear ARO for Non-Regulatory Agreement Units;
Lower nuclear fuel costs due to the absence of accelerated amortization of nuclear fuel and lower prices; and
The reversal of a charge related to a 2012 prior merger commitment

The favorable items were partially offset by:

Unfavorable mark-to-market activity;
Unfavorable net realized and unrealized NDT activity;
Lower capacity revenues;
Higher labor, contracting and materials;
Unfavorable impacts from nuclear outages;
Higher separation costs; and
The absence of a prior year gain on the sale of our solar business

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

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

For the three and nine months ended September 30, 2022 compared to 2021, Operating revenues by region were as follows:


	Three Months Ended September 30,								Nine Months Ended September 30,
	2022		2021		Variance		% Change(a)		2022		2021		Variance		% Change(a)
Mid-Atlantic	$	1,659	$	1,272	$	387	30.4	%	$	3,967	$	3,527	$	440	12.5	%
Midwest	1,047		985		62		6.3	%	3,345		2,945		400		13.6	%
New York	423		455		(32)		(7.0)	%	1,178		1,173		5		0.4	%
ERCOT	490		358		132		36.9	%	1,210		890		320		36.0	%
Other Power Regions	1,936		1,260		676		53.7	%	5,189		3,729		1,460		39.2	%
Total electric revenues	5,555		4,330		1,225		28.3	%	14,889		12,264		2,625		21.4	%
Other	1,177		711		466		65.5	%	4,117		2,811		1,306		46.5	%
Mark-to-market losses	(681)		(635)		(46)				(1,899)		(958)		(941)
Total Operating revenues	$	6,051	$	4,406	$	1,645	37.3	%	$	17,107	$	14,117	$	2,990	21.2	%

(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 September 30,					Nine Months Ended September 30,
Supply Source (GWhs)	2022	2021	Variance	% Change		2022	2021	Variance	% Change
Nuclear Generation(a)
Mid-Atlantic	13,540	13,753	(213)	(1.5)	%	39,272	40,203	(931)	(2.3)	%
Midwest	24,275	23,909	366	1.5	%	71,079	70,363	716	1.0	%
New York(b)	5,979	6,688	(709)	(10.6)	%	18,563	19,820	(1,257)	(6.3)	%
Total Nuclear Generation	43,794	44,350	(556)	(1.3)	%	128,914	130,386	(1,472)	(1.1)	%
Natural Gas, Oil, and Renewables
Mid-Atlantic	230	491	(261)	(53.2)	%	1,573	1,675	(102)	(6.1)	%
Midwest	126	177	(51)	(28.8)	%	774	763	11	1.4	%
New York	—	—	—	—	%	—	1	(1)	(100.0)	%
ERCOT	4,987	4,670	317	6.8	%	10,873	10,250	623	6.1	%
Other Power Regions	2,401	2,409	(8)	(0.3)	%	7,179	7,641	(462)	(6.0)	%
Total Natural Gas, Oil, and Renewables	7,744	7,747	(3)	—	%	20,399	20,330	69	0.3	%
Purchased Power
Mid-Atlantic	6,508	4,565	1,943	42.6	%	12,164	12,123	41	0.3	%
Midwest	74	77	(3)	(3.9)	%	425	386	39	10.1	%

ERCOT	705	595	110	18.5	%	2,855	2,626	229	8.7	%
Other Power Regions	13,869	13,585	284	2.1	%	39,964	38,778	1,186	3.1	%
Total Purchased Power	21,156	18,822	2,334	12.4	%	55,408	53,913	1,495	2.8	%
Total Supply/Sales by Region
Mid-Atlantic	20,278	18,809	1,469	7.8	%	53,009	54,001	(992)	(1.8)	%
Midwest	24,475	24,163	312	1.3	%	72,278	71,512	766	1.1	%
New York(b)	5,979	6,688	(709)	(10.6)	%	18,563	19,821	(1,258)	(6.3)	%
ERCOT	5,692	5,265	427	8.1	%	13,728	12,876	852	6.6	%
Other Power Regions	16,270	15,994	276	1.7	%	47,143	46,419	724	1.6	%
Total Supply/Sales by Region	72,694	70,919	1,775	2.5	%	204,721	204,629	92	—	%

(a)Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. Includes the total output for fully owned plants and the total output for CENG prior to the acquisition of EDF’s interest on August 6, 2021 as CENG was fully consolidated. See Note 2 — Mergers, Acquisitions, and Dispositions of our 2021 Form 10-K for additional information on our acquisition of EDF’s interest in CENG.

(b)2021 values have been revised from those previously reported to correctly reflect our 82% undivided ownership interest in Nine Mile Point Unit 2.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Nuclear fleet capacity factor(a)	96.4	%	97.7	%	94.5	%	95.3	%
Refueling outage days	5		22		147		172
Non-refueling outage days	26		—		51		10

(a)Prior year capacity factor was previously reported as 96.0% and 95.0% for the three and nine months ended September 30, 2021, respectively. The update reflects a change to the ratio from using the full average annual mean capacity to the net monthly mean capacity when calculating capacity factor. There is no change to actual output and the full year capacity factor would be the same under both methodologies.

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, 2022 and 2021.


	Three Months Ended September 30,								Nine Months Ended September 30,
State (Region)(a)	2022		2021		Variance		% Change		2022		2021		Variance		% Change
New Jersey (Mid-Atlantic)	$	10.00	$	10.00	$	—	—	%	$	10.00	$	10.00	$	—	—	%
Illinois (Midwest)(b)	12.01		16.50		(4.49)		(27.2)	%	14.50		16.50		(2.00)		(12.1)	%
New York (New York)	21.38		21.38		—		—	%	21.38		20.78		0.60		2.9	%

(a)See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on the plants receiving payments through state programs.

(b)Subject to a cap on total consideration to be received by us for each delivery period. See Note 4 — Revenue from Contracts with Customers for additional information.

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 and nine months ended September 30, 2022, the average CMC price per MWh was a net negative value ($51.70) and ($51.85), respectively. See Note 3 - Regulatory Matters of our 2021 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 tables present the average capacity reference prices ($/MW Day) for each of our major regions. Prices reflect the weighted averages for the various auction periods within the three and nine months ended September 30, 2022 and 2021.


	Three Months Ended September 30,								Nine Months Ended September 30,
Location (Region)	2022		2021		Variance		% Change		2022		2021		Variance		% Change
Eastern Mid-Atlantic Area Council (Mid-Atlantic)	$	97.86	$	165.73	$	(67.87)	(41.0)	%	$	135.57	$	178.03	$	(42.46)	(23.8)	%
ComEd (Midwest)	68.96		195.55		(126.59)		(64.7)	%	139.29		191.42		(52.13)		(27.2)	%
Rest of State (New York)	108.22		164.40		(56.18)		(34.2)	%	89.67		98.47		(8.80)		(8.9)	%
Southeast New England (Other)	126.67		154.37		(27.70)		(17.9)	%	142.06		166.76		(24.70)		(14.8)	%

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)	2022		2021		Variance		% Change		2022		2021		Variance		% Change
PJM West (Mid-Atlantic)	$	90.43	$	41.81	$	48.62	116.3	%	$	74.33	$	33.78	$	40.55	120.0	%
ComEd (Midwest)	81.99		39.70		42.29		106.5	%	62.90		31.87		31.03		97.4	%
Central (New York)	74.96		36.29		38.67		106.6	%	60.89		26.68		34.21		128.2	%
North (ERCOT)	97.58		39.18		58.40		149.1	%	68.47		193.18		(124.71)		(64.6)	%
Southeast Massachusetts (Other)(a)	86.27		43.82		42.45		96.9	%	89.01		41.18		47.83		116.1	%

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

For the three and nine months ended September 30, 2022 compared to 2021, changes in Operating revenues by region were approximately as follows:



	Variance		% Change(a)		Three Months Ended September 30	Variance		% Change(a)		Nine Months Ended September 30
Mid-Atlantic	$	387	30.4	%	• favorable wholesale load revenue of $210 primarily due to higher energy prices and higher volumes • favorable retail load revenue of $180 primarily due to higher energy prices	$	440	12.5	%	• favorable retail load revenue of $415 primarily due to higher energy prices • favorable wholesale load revenue of $100 primarily due to higher energy prices partially offset by lower volumes; partially offset by • unfavorable settled economic hedges of ($60) due to settled prices relative to hedged prices


Midwest	62		6.3	%	• favorable retail load revenue of $120 primarily due to higher energy prices; partially offset by • unfavorable net wholesale load and generation revenue of ($35) primarily due to lower cleared capacity volumes	400		13.6	%	• favorable net wholesale load and generation revenue of $460 primarily due to higher energy prices and higher volumes, partially offset by CMC program activity and lower cleared capacity volumes • favorable retail load revenue of $220 primarily due to higher energy prices; partially offset by • unfavorable settled economic hedges of ($270) due to settled prices relative to hedged prices
New York	(32)		(7.0)	%	• unfavorable settled economic hedges of ($125) due to settled prices relative to hedged prices; partially offset by • favorable retail load revenue of $95 primarily due to higher energy prices and higher volumes	5		0.4	%	• favorable retail load revenue of $235 primarily due to higher energy prices and higher volumes • favorable generation revenue of $115 primarily due to higher energy prices partially offset by lower nuclear generation due to an increase in outage days; partially offset by • unfavorable settled economic hedges of ($325) due to settled prices relative to hedged prices
ERCOT	132		36.9	%	• favorable retail load revenue of $110 primarily due to higher energy prices and higher volumes	320		36.0	%	• favorable settled economic hedges of $335 due to settled prices relative to hedged prices • favorable retail load revenue of $70 primarily due to higher volumes partially offset by lower energy prices relative to the prior year due to the February 2021 extreme cold weather event; partially offset by • unfavorable wholesale load revenue of ($65) primarily due to lower energy prices relative to the prior year due to the February 2021 extreme cold weather event
Other Power Regions	676		53.7	%	• favorable wholesale load revenue of $340 primarily due to higher energy prices and higher volumes • favorable settled economic hedges of $180 due to settled prices relative to hedged prices • favorable retail load revenue of $135 primarily due to higher energy prices	1,460		39.2	%	• favorable wholesale load revenue of $590 primarily due to higher energy prices and higher volumes • favorable settled economic hedges of $535 due to settled prices relative to hedged prices • favorable retail load revenue of $295 primarily due to higher energy prices and higher volumes
Other	466		65.5	%	• favorable gas revenue, including settled financial hedges, of $510 primarily due to higher gas prices	1,306		46.5	%	• favorable gas revenue, including settled financial hedges, of $1,360 primarily due to higher gas prices • favorable energy revenue of $190 primarily due to higher energy prices; partially offset by • unfavorable impact due to the absence of the customer pass through impact of LDC and pipeline penalties due to the February 2021 extreme cold weather event of ($220)
Mark-to-market(b)	(46)				• losses on economic hedging activities of ($681) in 2022 compared to losses of ($635) in 2021	(941)				• losses on economic hedging activities of ($1,899) in 2022 compared to losses of ($958) in 2021
Total	$	1,645	37.3	%		$	2,990	34.6	%

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

(b)See Note 12 — 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.

For the three and nine months ended September 30, 2022 compared to 2021, Purchased power and fuel by region were as follows:


	Three Months Ended September 30,								Nine Months Ended September 30,
	2022		2021		Variance		% Change(a)		2022		2021		Variance		% Change(a)
Mid-Atlantic	$	1,104	$	702	$	(402)	(57.3)	%	$	2,355	$	1,815	$	(540)	(29.8)	%
Midwest	475		330		(145)		(43.9)	%	1,335		930		(405)		(43.5)	%
New York	156		109		(47)		(43.1)	%	351		293		(58)		(19.8)	%
ERCOT	424		179		(245)		(136.9)	%	975		1,812		837		46.2	%
Other Power Regions	1,679		1,049		(630)		(60.1)	%	4,479		3,165		(1,314)		(41.5)	%
Total electric purchased power and fuel	3,838		2,369		(1,469)		(62.0)	%	9,495		8,015		(1,480)		(18.5)	%
Other	1,014		566		(448)		(79.2)	%	3,587		2,288		(1,299)		(56.8)	%
Mark-to-market gains	(157)		(1,389)		(1,232)				(1,328)		(2,200)		(872)
Total purchased power and fuel	$	4,695	$	1,546	$	(3,149)	(203.7)	%	$	11,754	$	8,103	$	(3,651)	(45.1)	%

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

For the three and nine months ended September 30, 2022 compared to 2021, changes in Purchased power and fuel by region were approximately as follows:



	Variance		% Change(a)		Three Months Ended September 30	Variance		% Change(a)		Nine Months Ended September 30
Mid-Atlantic	$	(402)	(57.3)	%	• unfavorable purchased power and net capacity impact of ($400) primarily due to higher energy prices, lower capacity prices earned and lower nuclear generation	$	(540)	(29.8)	%	• unfavorable purchased power and net capacity impact of ($565) primarily due to higher energy prices, lower nuclear generation, and lower capacity prices earned; partially offset by • favorable settlement of economic hedges of $40 due to settled prices relative to hedged prices
Midwest	(145)		(43.9)	%	• unfavorable purchased power and net capacity impact of ($160) primarily due to higher energy prices and lower capacity prices earned	(405)		(43.5)	%	• unfavorable purchased power and net capacity impact of ($485) primarily due to higher energy prices, higher load, and lower capacity prices earned; partially offset by • favorable nuclear fuel cost of $80 primarily due to accelerated amortization of nuclear fuel in prior periods


New York	(47)		(43.1)	%	• unfavorable purchased power and net capacity impact of ($40) primarily due to higher energy prices, higher load, and lower capacity prices earned	(58)		(19.8)	%	• unfavorable purchased power and net capacity impact of ($140) primarily due to higher energy prices, higher load, and lower nuclear generation; partially offset by • favorable settlement of economic hedges of $90 due to settled prices relative to hedged prices
ERCOT	(245)		(136.9)	%	• unfavorable purchased power of ($110) primarily due to higher energy prices, higher load, and absence of favorable recovery related to the February 2021 extreme cold weather event • unfavorable settlement of economic hedges of ($105) due to settled prices relative to hedged prices • unfavorable fuel cost of ($30) primarily due to higher gas prices relative to the prior year	837		46.2	%	• favorable purchased power of $590 primarily due to lower energy prices relative to the prior year due to the February 2021 extreme cold weather event • favorable settlement of economic hedges of $155 due to settled prices relative to hedged prices • favorable fuel cost of $80 primarily due to lower gas prices relative to the prior year due to the February 2021 extreme cold weather event
Other Power Regions	(630)		(60.1)	%	• unfavorable purchased power and net capacity impact of ($635) primarily due to higher energy prices and higher load • unfavorable fuel cost of ($120) primarily due to higher gas prices; partially offset by • unfavorable environmental product optimization of ($60); partially offset by • favorable settlement of economic hedges of $200 due to settled prices relative to hedged prices	(1,314)		(41.5)	%	• unfavorable purchased power and net capacity impact of ($1,775) primarily due to higher energy prices, higher load, lower generation and lower cleared capacity volumes • unfavorable fuel cost of ($340) primarily due to higher gas prices • unfavorable environmental product optimization of ($80); partially offset by • favorable settlement of economic hedges of $900 due to settled prices relative to hedged prices
Other	(448)		(79.2)	%	• unfavorable net gas purchase costs and settlement of economic hedges of ($465)	(1,299)		(56.8)	%	• unfavorable net gas purchase costs and settlement of economic hedges of ($1,545) • unfavorable energy purchases of ($155) primarily due to higher energy prices • unfavorable fair value adjustment related to gas imbalances of ($100); partially offset by • favorable impact due to the absence of LDC and pipeline penalties due to the February 2021 extreme cold weather event of $330 • favorable impact due to the absence of accelerated nuclear fuel amortization associated with announced early plant retirements of $150
Mark-to-market(b)	(1,232)				• gains on economic hedging activities of $157 in 2022 compared to gains of $1,389 in 2021	(872)				• gains on economic hedging activities of $1,328 in 2022 compared to gains of $2,200 in 2021
Total	$	(3,149)	(203.7)	%		$	(3,651)	(45.1)	%

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

(b)See Note 12 — 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, 2022 compared to 2021, 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)	$	153	$	180
Plant retirements and divestitures(b)	94		88
Separation costs(c)	14		56
Credit loss expense(d)	(1)		(45)
COVID-19 direct costs	(5)		(24)
Nuclear refueling outage costs, including the co-owned Salem generating units	(17)		59
Asset impairments	(45)		(537)
Prior merger commitment(e)	(50)		(50)
Decommissioning-related activities(f)	(99)		287


Other	7		39
Total (decrease) increase	$	51	$	53

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

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

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

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

(f)Primarily reflects contractual offset of accelerated depreciation and amortization associated with our previous decision to early retire the Byron and Dresden nuclear facilities. See Note 10 — Asset Retirement Obligations of our 2021 Form 10-K for additional information.

Depreciation and amortization expense decreased for the three and nine months ended September 30, 2022 compared to the same period in 2021, primarily due to the accelerated depreciation and amortization associated with our previous decision to early retire the Byron and Dresden nuclear facilities. This decision was reversed on September 15, 2021 and depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. A portion of this accelerated depreciation and amortization is offset in Operating and maintenance expense.

Taxes other than income taxes increased for the three and nine months ended September 30, 2022 compared to the same period in 2021, primarily due to increased gross receipt tax related to our retail operations. The offsetting collection of gross receipts tax related to our retail operations is recorded in Operating revenues.

(Loss) gain on sales of assets and businesses decreased for the three and nine months ended September 30, 2022 compared to the same period in 2021, primarily due to gains on sales of equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021 and a gain on sale of our solar business in 2021.

Interest expense, net decreased for the three and nine months ended September 30, 2022 compared to the same period in 2021, primarily due to mark-to-market gains related to our CR and West Medway II interest rate swaps and the retirement of long-term debt in March 2022. See Note 17 — Debt and Credit Agreements of our 2021 Form 10-K for additional information on the CR credit facility and interest rate swaps.

Other, net decreased for the three and nine months ended September 30, 2022 compared to the same period in 2021, due to activity described in the table below:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net unrealized (losses) gains on NDT funds(a)	$	(225)	$	(94)	$	(1,077)	$	33
Net realized (losses) gains on sale of NDT funds(a)	(7)		101		45		349
Interest and dividend income on NDT funds(a)	22		26		70		73
Contractual elimination of income tax expense(b)	(63)		11		(284)		150
Non-service net periodic benefit credit(c)	27		—		79		—
Net unrealized (losses) gains from CTV investments(d)	(2)		(179)		(27)		(83)
Return to provision adjustment(e)	26		—		(32)		—
TSA billings(f)	12		—		32		—
Other	14		20		25		39
Total Other, net	$	(196)	$	(115)	$	(1,169)	$	561

(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)Historically, 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 11 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.

(d)Net unrealized gains and losses from CTV investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.

(e)This reflects amounts contractually owed to Exelon under the tax matters agreement, which is offset in Income taxes. See Note 10 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

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

Effective income tax rates were 39.4% and 21.7% for the three months ended September 30, 2022 and 2021, respectively, and 73.1% and (1350.0)% for the nine months ended September 30, 2022 and 2021, respectively. The effective tax rate in 2022 is primarily due to the impacts of higher unrealized NDT losses on Income before income taxes and one-time income tax adjustments. See Note 10 — 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, 2022 and includes CENG and CRP for the same period in 2021. The decrease for the three and nine months ended September 30, 2022, compared to the same period in 2021, is primarily due to our acquisition of EDF's interest in CENG on August 6, 2021. See Note 2 - Mergers, Acquisitions, and Dispositions of our 2021 Form 10-K for additional information.

Significant 2022 Transactions and Developments

Separation from Exelon

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate its competitive generation and customer-facing energy businesses into a stand-alone publicly traded company (the "separation"). Exelon completed the separation on February 1, 2022. We incurred separation costs of $30 million and $99 million for the three and nine months ended September 30, 2022, respectively, which are primarily recorded in Operating and maintenance expense. Separation costs for the three and nine months ended September 30, 2021 were not material. 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. These costs have been excluded from Adjusted EBITDA (non-GAAP). See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information.

Other Key Business Drivers

Power Markets

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 therefore, we have enough nuclear fuel to support all our refueling needs for multiple years regardless of sanctions. We are taking 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. We are also working with Federal policymakers and other stakeholders to facilitate the expansion of the domestic nuclear fuel cycle within the United States to improve carbon-free energy security.

Hedging Strategy

We are exposed to commodity price risk associated with the unhedged portion of our electricity portfolio. We enter into non-derivative and derivative contracts, including options, swaps, and forward and futures contracts, all with credit-approved counterparties, to hedge this anticipated exposure. For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis. We may also enter into transactions that are outside of this ratable hedging program. As of September 30, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 97%-100% and 92%-95% for 2022 and 2023, respectively. We have been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.

We procure natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 55% of our uranium concentrate requirements from 2022 through 2026 are supplied by three suppliers. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements.

See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

Other Environmental Regulation

Federal Climate Change Legislation and Regulation. On August 16, 2022, Congress passed and President Biden signed into law the Inflation Reduction Act of 2022, which, among other things, includes federal tax credits, certain of which are transferable or fully refundable, for clean energy technologies including existing nuclear plants and hydrogen production facilities. The Nuclear PTC recognizes the contributions of carbon-free nuclear power by providing a federal tax credit of up to $15/MWh, subject to phase-out, beginning in 2024 and continuing through 2032. The Hydrogen PTC provides a 10-year federal tax credit of up to $3/kilogram for clean hydrogen produced after 2022 from facilities that begin construction prior to 2033. Both the Nuclear and Hydrogen PTCs include adjustments for inflation. The Hydrogen PTC creates additional opportunities for our nuclear fleet to enable decarbonization of other industries through the production of clean hydrogen. With this policy support, we expect that many of our nuclear assets will operate through the end of the Nuclear PTC period.

Regulation of GHGs from Power Plants under the Clean Air Act. The EPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act Section 111(d). The CPP’s carbon pollution limits could be met through shifting generation from higher-emitting units to lower- or zero-emitting units. In July 2019, the EPA published the Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines based on heat rate improvement measures. We, as part of Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the Affordable Clean Energy Rule. On October 29, 2021, the Supreme Court granted certiorari to examine the extent of EPA’s authority to regulate GHGs from power plants. The electric utilities coalition filed a brief and participated in oral argument before the Supreme Court. On June 30, 2022, the Supreme Court issued a decision holding that EPA did not have the authority to require “generation shifting” from coal to natural gas and renewables to reduce sector-wide emissions, as it had done in CPP. The EPA has indicated it will promulgate new GHG limits for existing power plants in March 2023.

State Climate Change Legislation and Regulation. On July 1, 2022, Pennsylvania formally began participation in the RGGI, joining Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia. The program requires most fossil fuel-fired power plants in the region to hold allowances, sold at auction or on the secondary market, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances. The process of bringing Pennsylvania into the RGGI began in October 2019 when the Governor of Pennsylvania signed an Executive Order directing the PA DEP to commence the rulemaking to join the RGGI and that rule went into effect with Pennsylvania joining RGGI on July 1, 2022. However, on July 8, 2022, the Commonwealth Court of Pennsylvania entered two preliminary injunctions preventing Pennsylvania from participating in RGGI while ongoing legal challenges proceed. At least one of those injunctions currently remains in place while it is appealed to the Pennsylvania Supreme Court, where briefing of the appeal will be completed by December 4, 2022. In addition, the Commonwealth Court of Pennsylvania is scheduled to hear oral arguments in November 2022 on the merits of the challenges to Pennsylvania entering RGGI. On September 26, the Virginia State Air Pollution Control Board published a Notice of Intended Regulatory Action to begin the process for repealing "Regulation for Emissions Trading," which implemented Virginia's participation in RGGI. The Virginia Department of Environmental Quality was directed to reevaluate Virginia's participation in RGGI and begin a regulatory process to end it per a governor's order.

Mercury and Air Toxics Standards (MATS). In 2011, the EPA signed a final rule, known as MATS, to reduce emissions of hazardous air pollutants from coal- and oil-fired power plants. MATS requires coal-fired power plants to achieve high removal rates of mercury, acid gases, and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. This rule has been subject to various challenges since issuance, see PART I, ITEM 1. BUSINESS of our 2021 Form 10-K for additional information on the procedural history of this matter. On January 20, 2021, President Biden issued an Executive Order directing the EPA to reconsider its May 22, 2020, revised supplemental finding, and the EPA subsequently moved for the U.S. Court of Appeals for the D.C. Circuit to place the cases challenging that finding in abeyance pending its reconsideration, which the court did on February 21, 2021. On February 9, 2022 EPA published a proposal to revoke the 2020 revised supplemental finding and reaffirm that it is "appropriate and necessary" to regulate hazardous air pollutant emissions from coal- and oil-fired power plants. Additionally, in February 2022, the U.S. Court of Appeals for the D.C. Circuit granted unopposed motions to substitute Constellation in place of Exelon in these cases. Comments on the proposed regulation were due April 11, 2022. If EPA promulgates a final rule revoking the 2020 revised supplemental finding determination, then the cases currently before the U.S. Court of Appeals for the D.C. Circuit concerning MATS may be dismissed as moot or placed in abeyance pending the disposition of any petitions for review that may be filed challenging that final rule. We cannot reasonably predict the outcome of this matter.

Critical Accounting Policies and Estimates

Management makes a number of significant estimates, assumptions, and judgements in the preparation of our financial statements. The following policy was added as a result of separation. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in our 2021 Form 10-K for further information.

Retirement Benefits

Defined Benefit Pension and Other Postretirement Employee Benefits

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

Pension and OPEB plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity, and hedge funds.

Expected Rate of Return on Plan Assets. In determining the EROA, we consider historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by our target asset class allocations. We calculate the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, we use a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, we use fair value to calculate the MRV.

Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. We utilize an analytical tool developed by our actuaries to determine the discount rates.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. In 2022, we adopted the revised mortality tables and projection scales released by the SOA.

Sensitivity to Changes in Key Assumptions. The following table illustrates the effects of changing certain of the actuarial assumptions reflected above on the remeasurement completed at separation as discussed in Note 11 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements, while holding all other assumptions constant:


	Actual Assumption
	Pension		OPEB		Assumption			Increase / (Decrease)
Actuarial Assumption			Pension				OPEB			Total
Change in 2022 cost:
Discount rate(a)	3.23	%	3.21	%	0.5	%		$	(22)		$	(1)	$	(23)
	3.23	%	3.21	%	(0.5)	%		28			7		35
EROA	7.00	%	6.50	%	0.5	%		(41)			(4)		(45)
	7.00	%	6.50	%	(0.5)	%		41			4		45
Change in benefit obligation:
Discount rate(a)	3.23	%	3.21	%	0.5	%		(536)			(99)		(635)
	3.23	%	3.21	%	(0.5)	%		620			115		735

(a)In general, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, we utilize a liability-driven hedging investment strategy for our pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.

See Note 1 — Basis of Presentation and Note 11 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension and OPEB plans.

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 various facilities with aggregate bank commitments of $5.8 billion. We utilize these facilities to support our commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 13 — 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 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

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

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

As of September 30, 2022, we are not required to provide any additional financial assurance for TMI Unit 1 under the SAFSTOR scenario that is the planned decommissioning option, as described in the TMI Unit 1 PSDAR filed with the NRC on April 5, 2019. On October 16, 2019, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request to allow the TMI Unit 1 NDT funds to be used for site restoration costs was submitted to the NRC on May 20, 2021. On June 8, 2022, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for site restoration costs.

Cash Flows from Operating Activities

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

See Note 3 — Regulatory Matters and Note 15 — 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, 2022 and 2021:


Increase (decrease) in cash flows from operating activities
Net loss	$	(73)
Adjustments to reconcile net income to cash:
Collateral received, net	(1,208)
Changes in working capital and other noncurrent assets and liabilities	(617)
Pension and non-pension postretirement benefit contributions	8
Option premiums paid, net	23
Income taxes	187
Other non-cash operating activities	775
Decrease in cash flows from operating activities	$	(905)

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, 2022 and 2021 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 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral.
Changes in working capital and other noncurrent assets and liabilities** primarily reflect reduced DPP consideration related to the revolving accounts receivable financing arrangement entered into on April 8, 2020, a decrease in Accounts payable resulting from the impact of certain penalties for natural gas delivery associated with the February 2021 extreme cold weather event, increased inventory due to rising gas prices and decreased sales of emissions allowances. There is a partial offset for this decrease due to increases in Accounts payable related to rising gas prices and the Illinois CMC program, and reimbursements of costs associated with the storage of SNF. Additionally, there is a partial offset for this decrease in Cash Flows from Investing activities due to cash proceeds received from the Purchasers during the first quarter of 2021. See Note 6 — Accounts Receivable and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivable and on the February 2021 extreme cold weather event, respectively and Note 19 — Commitments and Contingencies of our 2021 Form 10-K for additional information on the storage of SNF.
See Note 10 —Income Taxes of the Combined Notes to Consolidated Financial Statements and the Consolidated Statements of Cash Flows for additional information on income taxes.
See Note 19 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

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, 2022 and 2021:


(Decrease) increase in cash flows from investing activities
Proceeds from sales of assets and businesses	(761)
Investment in NDT funds, net	(44)

Capital expenditures	(4)
Collection of DPP, net	43
Other investing activities	(2)
Decrease in cash flows from investing activities	$	(768)

Significant investing cash flow impact for the nine months ended September 30, 2022 and 2021 was as follows:

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

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, 2022 and 2021:


(Decrease) increase in cash flows from financing activities
Contribution from Exelon	$	1,686
Distributions to Exelon	1,373
Acquisition of CENG noncontrolling interest	885
Changes in money pool with Exelon	285
Dividends paid on common stock	(139)
Long-term debt, net	(1,455)
Changes in short-term borrowings, net	(1,929)
Other financing activities	2
Increase in cash flows from financing activities	$	708

Significant financing cash flow impacts for the nine months ended September 30, 2022 and 2021 were as follows:

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.
Distributions to Exelon** relate to distributions made prior to separation. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation.
See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the acquisition of CENG noncontrolling interest.
Changes in money pool with Exelon** were driven by short-term borrowing needs prior to the separation on February 1, 2022. Exelon operated a money pool for its subsidiaries that provided an additional short-term borrowing option that was generally more favorable to the borrowing participants than the cost of external financing.
Long-term debt, net,** varies due to debt issuances and redemptions each year. Refer to Note 13 - Debt and Credit Agreements below for additional information.
Changes in short-term borrowings, net**, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.

Dividends

Quarterly dividends declared by our Board of Directors during the nine months ended September 30, 2022 and for the third quarter of 2022 were as follows:


Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share
First Quarter of 2022	February 8, 2022	February 25, 2022	March 10, 2022	$	0.1410
Second Quarter of 2022	April 26, 2022	May 13, 2022	June 10, 2022	$	0.1410
Third Quarter of 2022	July 26, 2022	August 15, 2022	September 9, 2022	$	0.1410
Fourth Quarter of 2022	October 31, 2022	November 15, 2022	December 9, 2022	$	0.1410

Credit Matters and Cash Requirements

We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of September 30, 2022, we have access to facilities with aggregate bank commitments of $5.8 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during the third quarter of 2022 to fund our short-term liquidity needs, when necessary. We used our available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2021 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 lost our investment grade credit rating as of September 30, 2022, we would have been required to provide incremental collateral estimated to be approximately $3.1 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements. As of September 30, 2022, we had $2.2 billion of available capacity and $1.2 billion of cash on hand. In the event of a credit downgrade that required us to provide incremental collateral exceeding our available capacity, we would be required to access additional liquidity through the capital markets. See Note 12 — Derivative Financial Instruments and Note 13 — 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 Act), and management of the pension obligation. The 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 on an ABO basis 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, we made our annual qualified pension contribution totaling $192 million in February 2022. Unlike the qualified pension plans, our non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

While OPEB plans are also not subject to statutory minimum contribution requirements, we do fund certain of our plans. For our funded OPEB plans, contributions generally equal accounting costs; however, we consider several factors in determining the level of contributions to our OPEB plans, including liabilities management and levels of benefit claims paid. The estimated benefit payments to the non-qualified pension plans in 2022 are $21 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans is $27

million. The benefit payments to the non-qualified pension plans and OPEB plans for the nine months ended September 30, 2022 were $16 million and $21 million, respectively.

To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if we change our pension or OPEB funding strategy. See Note 11 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.

Cash Requirements for Other Financial Commitments

Refer to Liquidity and Capital Resources of our 2021 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 2021 Form 10-K for additional information on our project finance structures 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 13 — 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 facility 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 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

At separation, S&P and Moody's affirmed our senior unsecured ratings of BBB- and Baa2, respectively. Fitch also affirmed their final rating of BBB, prior to formally withdrawing coverage on January 5th. We have only engaged S&P and Moody's for ratings coverage following separation. Subsequently, on October 13, 2022, S&P raised our senior unsecured debt rating to 'BBB' from 'BBB-' citing the passage of the IRA of 2022 as a material credit positive for us.

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