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What changed in Constellation Energy's 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of Constellation Energy's 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+505 added−489 removedSource: 10-K (2024-02-27) vs 10-K (2023-02-16)

Top changes in Constellation Energy's 2023 10-K

505 paragraphs added · 489 removed · 382 edited across 7 sections

Item 1. Business

Business — how the company describes what it does

148 edited+38 added−40 removed93 unchanged
Biggest changeA 100% reduction of our operations-driven emissions by 2040, including an interim goal to reduce carbon emissions by 65% from 2020 levels by 2030 and reduce methane emissions 30% from 2020 by 2030, and 3. Providing 100% of C&I customers with specific information about their GHG impact.
Biggest changeWe are committed to reducing our GHG emissions and enabling our C&I customers through the following: • Achieving a generation portfolio mix with 100% of our owned generation carbon-free by 2040, including an interim goal of 95% carbon-free by 2030, subject to policy support and technology advancements, • A 100% reduction of our operations-driven emissions by 2040, including an interim goal to reduce carbon emissions by 65% from 2020 levels by 2030 and reduce methane emissions 30% from 2020 by 2030, subject to policy support and technology advancements and • Prior to the end of 2022, successfully delivered on our commitment to provide 100% of our C&I customers with customer-specific information on their GHG impact for facilities contracting for power or gas supply from Constellation, that include hourly carbon-free energy matching.
Peach Bottom has previously received a second 20-year license renewal from the NRC, for a total 80-year term, for Units 2 and 3.
Peach Bottom has previously received a second 20-year license renewal from the NRC for Units 2 and 3, for a total 80-year term.
Complementary to our national portfolio, we have several decades of relationships with wholesale counterparties across all domestic power markets as a means of both monetizing our own generation, as well as sourcing contracted generation to meet customer and portfolio needs.
Complementary to our national customer portfolio, we have several decades of relationships with wholesale counterparties across all domestic power markets as a means of both monetizing our own generation, as well as sourcing contracted generation to meet customer and portfolio needs.
These types of data and analytical services allow us to grow our customer base in previously inaccessible regulated markets by offering non-commodity energy-related products. Our Constellation Technology Ventures’ commercialization team invests in, and collaborates with, portfolio companies to deploy products and technologies across our broad customer base to drive value for both us and portfolio companies.
These types of data and analytical services allow us to grow our customer base in previously inaccessible regulated markets by offering non-commodity energy-related products and services. Our Constellation Technology Ventures’ commercialization team invests in, and collaborates with, portfolio companies to deploy products and technologies across our broad customer base to drive value for both us and portfolio companies.
ITEM 1. General On February 21, 2021, the Board of Directors of Exelon Corporation (“Exelon”) authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly traded company.
ITEM 1. BUSINESS General On February 21, 2021, the Board of Directors of Exelon Corporation (“Exelon”) authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly traded company.
Changes in regulations by the NRC may require a substantial increase in capital expenditures and/or operating costs for our nuclear generating facilities. NRC regulations also require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility.
Changes in requirements by the NRC may require a substantial increase in capital expenditures and/or operating costs for our nuclear generating facilities. NRC regulations also require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility.
The commodity risks associated with the output from owned and contracted generation are managed using various commodity transactions including sales to retail customers, trades on commodity exchanges, and sales to wholesale counterparties in accordance with our ratable hedging program. See further discussion of the ratable hedging program in the Price and Supply Risk Management section below.
The commodity risks associated with the output from owned and contracted generation are managed using various commodity transactions including sales to retail customers, trades on commodity exchanges, and sales to wholesale counterparties in accordance with our hedging program. See further discussion of the hedging program in the Price and Supply Risk Management section below.
Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on these dispositions. __________ (a) Dispatch Match is used to measure the responsiveness of a unit to the market, expressed as the total actual energy revenue net of fuel cost relative to the total desired energy revenue net of fuel cost.
See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on these dispositions. __________ (a) Dispatch Match is used to measure the responsiveness of a unit to the market, expressed as the total actual energy revenue net of fuel cost relative to the total desired energy revenue net of fuel cost.
Policy Support for Decarbonization and Emerging Carbon-Free Technologies. Driven by societal concerns about climate change, governments, corporations, and investors are increasingly advocating for the reduction of GHG emissions across all sectors of the economy, with reduction of GHG emissions by the energy sector being a key focus.
Policy Support for Decarbonization and Emerging Carbon-Free Technologies. Driven by concerns about climate change, governments, corporations, and investors are increasingly advocating for the reduction of GHG emissions across all sectors of the economy, with reduction of GHG emissions by the energy sector being a key focus.
With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months is referred to as “favorable weather conditions” because those weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand.
With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months is generally referred to as “favorable weather conditions” because those weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand.
We produce electricity predominantly from low and carbon-free generating facilities (such as nuclear, hydroelectric, natural gas, wind, and solar) and neither own nor operate any coal-fueled generating assets. Our natural gas and oil generating plants produce GHG emissions, most notably CO2.
We produce electricity predominantly from low and carbon-free generating facilities (such as nuclear, hydroelectric, natural gas, wind, and solar) and neither own nor operate any coal-fueled generating assets. Our natural gas and oil generating plants produce some GHG emissions, most notably CO2.
Climate Change Driven by societal concerns about climate change, governments, corporations, and investors are increasingly advocating for the reduction of GHG emissions across all sectors of the economy, with reduction of GHG emissions by the energy sector being a key focus.
Climate Change Driven by concerns about climate change, governments, corporations, and investors are increasingly advocating for the reduction of GHG emissions across all sectors of the economy, with reduction of GHG emissions by the energy sector being a key focus.
We believe our generation fleet, including our nuclear assets, is well-positioned to deliver reliable, clean power and benefit from growing demand for carbon-free electricity.
We believe our generation fleet, including our nuclear assets, is well-positioned to deliver reliable, carbon-free power and benefit from growing demand for carbon-free electricity.
We partner with our customers to provide options along the sustainability continuum, including renewable, efficiency and technology solutions to meet their carbon-free energy goals. Our energy efficiency products provide the ability to optimize performance and maximize efficiency across customer facilities and operations through contract structures that include implementation of energy efficiency upgrades with no upfront capital requirements.
We partner with our customers to provide options along the sustainability continuum, including renewable, efficiency and digital solutions to meet their carbon-free energy goals. Our energy efficiency products provide the ability to optimize performance and maximize efficiency across customer facilities and operations through contract structures that include implementation of energy efficiency upgrades with no upfront capital requirements.
Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities.
Other matters subject to FERC jurisdiction include, but are not limited to, certain third-party financings; review of certain mergers involving public utilities; certain dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; certain affiliate transactions; certain intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities.
RISK FACTORS for additional information. 23 Table of Contents Climate Change Mitigation and Transition We support comprehensive federal climate legislation that addresses the climate crisis and would ensure the country meets the targets set by the Paris Climate Accord. Independent of additional legislation, we support the EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act.
RISK FACTORS for additional information. 22 Table of Contents Climate Change Mitigation and Transition We support comprehensive federal climate legislation that addresses the climate crisis and would ensure the country meets the targets set by the Paris Climate Accord. Independent of additional legislation, we support the EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act.
With increased customer demand for sustainability, our ability to source contracted generation has provided a capital-light way for us to provide customers with the sustainable solutions they are demanding to support a cleaner energy ecosystem. This creates durable customer relationships and repeatable business through the ability to respond to customer and marketplace trends.
With increased customer demand for sustainability, our ability to source contracted generation has provided a capital-light way for us to provide customers with long-term sustainable solutions they are demanding to support a cleaner energy ecosystem. This creates durable customer relationships and repeatable business through the ability to respond to customer and marketplace trends.
While this trend of customers using third parties to find suppliers has slowed in recent years, we have remained the market leader in direct sales with over 32% of the C&I market share of direct customer business driven by our highly experienced and long-tenor direct sales team.
While this trend of customers using third parties to find suppliers has slowed in recent years, we have remained the market leader in direct C&I sales with over 33% of the C&I market share of direct customer business driven by our highly experienced and long-tenor direct sales team.
Key drivers of increased demand for clean energy include: • Governmental and corporate policies designed to accelerate the decarbonization of the economy, • Policy support for nuclear energy sources that also enable energy security, reliability and diversification, • Rapid electrification of the U.S. economy, and • Evolving customer preferences favoring clean energy, choice and digitization.
Key drivers of increased demand for carbon-free energy include: • Governmental and corporate policies designed to accelerate the decarbonization of the economy, • Policy support for nuclear energy sources that also enable energy security, reliability and diversification, • Rapid electrification of the U.S. economy, and • Evolving customer preferences favoring clean energy, choice and digitization.
Such statutes apply in many states where we currently own or operate, or previously owned or operated facilities, including Illinois, Maryland, New Jersey, and Pennsylvania. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
Such statutes apply in many states where we currently own or operate, or previously owned or operated facilities, including Illinois, Maryland, New Jersey, Pennsylvania, New York, and Texas. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on our results of operations. In 2022, we achieved an average refueling outage duration of 21 days for units we operate.
Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on our results of operations. In 2023, we achieved an average refueling outage duration of 21 days for units we operate.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information. 10 Table of Contents The following table summarizes the current license expiration dates for our nuclear facilities currently in service: Station Unit In-Service Date (a) Current License Expiration Braidwood 1 1988 2046 2 1988 2047 Byron 1 1985 2044 2 1987 2046 Calvert Cliffs 1 1975 2034 2 1977 2036 Clinton (b) 1 1987 2027 Dresden (b) 2 1970 2029 3 1971 2031 FitzPatrick 1 1975 2034 LaSalle 1 1984 2042 2 1984 2043 Limerick 1 1986 2044 2 1990 2049 Nine Mile Point 1 1969 2029 2 1988 2046 Peach Bottom (c) 2 1974 2033 3 1974 2034 Quad Cities 1 1973 2032 2 1973 2032 Ginna 1 1970 2029 Salem 1 1977 2036 2 1981 2040 __________ (a) Denotes year in which nuclear unit began commercial operations.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information. 9 Table of Contents The following table summarizes the current license expiration dates for our nuclear facilities currently in service: Station Unit In-Service Date (a) Current License Expiration Braidwood 1 1988 2046 2 1988 2047 Byron 1 1985 2044 2 1987 2046 Calvert Cliffs 1 1975 2034 2 1977 2036 Clinton (b) 1 1987 2027 Dresden (b) 2 1970 2029 3 1971 2031 FitzPatrick 1 1975 2034 LaSalle 1 1984 2042 2 1984 2043 Limerick 1 1986 2044 2 1990 2049 Nine Mile Point (b) 1 1969 2029 2 1988 2046 Peach Bottom (c) 2 1974 2033 3 1974 2034 Quad Cities 1 1973 2032 2 1973 2032 Ginna (b) 1 1970 2029 Salem 1 1977 2036 2 1981 2040 STP 1 1988 2047 2 1989 2048 __________ (a) Denotes year in which nuclear unit began commercial operations.
Retail Market Retail competition in states across the U.S. range from full competition of energy suppliers for all retail customers (commercial, industrial and residential) to partial retail competition available up to a capped amount for C&I customers only.
Retail Market Retail competition in states across the U.S. range from full competition of energy suppliers for all retail customers (commercial, industrial, public sector, and residential) to partial retail competition available up to a capped amount for C&I customers only.
Governments at the international, national and state levels have established or are currently contemplating increasingly stringent policies that require the reduction of GHG emissions over time. Corporations have also adopted targets to reduce the carbon emissions in their business operations, spurred in part by demand from investors and customers for sustainable, environment-friendly business practices.
Governments at the international, national and state levels have established or are currently contemplating 18 Table of Contents increasingly stringent policies that require the reduction of GHG emissions over time. Corporations have also adopted targets to reduce the carbon emissions in their business operations, spurred in part by demand from investors and customers for sustainable, environment-friendly business practices.
We employ approximately 13,370 people, and do business in 48 states, the District of Columbia, Canada, and the United Kingdom. Our generation fleet produces more clean, carbon-free energy than any other company in the United States.
We employ approximately 13,871 people, and do business in 48 states, the District of Columbia, Canada, and the United Kingdom. Our generation fleet produces more clean, carbon-free energy than any other company in the United States.
Similarly, this contracting acumen provides the ability to supplement our native generation with other non-renewable assets to meet changing portfolio needs in a financially efficient manner. In 14 Table of Contents our wholesale gas business we participate across all parts of the gas value chain, including trading, transport and storage and physical supply.
Similarly, this contracting acumen provides the ability to supplement our native generation with other non-renewable assets to meet changing portfolio needs in a financially efficient manner. In our wholesale gas business we participate across all parts of the gas value chain, including trading, transport and storage and physical supply.
We have original 40-year operating licenses from the NRC for each of our nuclear units and have received 20-year operating license renewals from the NRC for all our nuclear units except Clinton. PSEG has received 20-year operating license renewals for Salem Units 1 and 2.
We have original 40-year operating licenses from the NRC for each of our nuclear units and have received 20-year operating license renewals from the NRC for all our nuclear units except Clinton. PSEG has received 20-year operating license renewals for Salem Units 1 and 2. STPNOC has received 20-year operating license renewals for STP Units 1 and 2.
As of December 31, 2022, we have established appropriate contingent liabilities for environmental remediation requirements. In addition, we may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
As of December 31, 2023, we have established appropriate contingent liabilities for environmental remediation requirements. In addition, we may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
Clean hydrogen also has the potential to drive decarbonization, particularly as it relates to more challenging sectors like long-haul transportation, steel, chemicals, heating, agriculture, and long-term power storage. Nuclear power can be used to produce clean hydrogen, and our nuclear fleet positions us well to explore this emerging space.
Clean hydrogen also has the potential to drive decarbonization, particularly as it relates to more challenging sectors like long-haul transportation, steel, chemicals, heating, agriculture, and long-term power storage. Nuclear power can be used to produce clean hydrogen, and our nuclear fleet positions us well to explore this emerging space with supportive policy.
Our operations are also subject to the jurisdiction of various other federal, state, regional, and local agencies, and federal and state environmental protection agencies. Additionally, we are subject to NERC mandatory 18 Table of Contents reliability standards, which protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.
Our operations are also subject to the jurisdiction of various other federal, state, regional, and local agencies, and federal and state environmental protection agencies. Additionally, we are subject to NERC mandatory reliability standards, which protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.
In addition, we sell natural gas t hrough our customer-facing business; and consumers’ use of such natural gas produces GHG emissions. However, our owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry.
In addition, we sell natural gas through our customer-facing business; and consumers’ use of such natural gas produces GHG emissions. However, our owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry.
Nuclear Waste Storage and Disposal 28 Table of Contents There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. We currently store all SNF generated by our nuclear generating facilities on-site in storage pools or in dry cask storage facilities.
Nuclear Waste Storage and Disposal There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. We currently store all SNF generated by our nuclear generating facilities on-site in storage pools or in dry cask storage facilities.
Natural Gas, Oil and Renewable Facilities (including Hydroelectric) We operate approximately 11 gigawatts of natural gas, oil, hydroelectric, wind, and solar generation assets, which provide a mix of baseload, intermediate, and peak power generation.
Natural Gas, Oil and Renewable Facilities (including Hydroelectric) We operate approximately 11 GWs of natural gas, oil, hydroelectric, wind, and solar generation assets, which provide a mix of baseload, intermediate, and peak power generation.
See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding our environmental matters, remediation efforts, and related impacts to our Consolidated Financial Statements.
See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding our environmental matters, remediation efforts, and related impacts to our Consolidated Financial Statements.
In response, we have expanded our third-party capabilities, created scale through a comprehensive support structure, and enhanced digital applications providing tools, tracking, and measurement, as well as the ability to extend the reach of our sustainability services and products to drive additional market share.
In response, we have expanded our third-party capabilities, created scale through a comprehensive support structure, and enhanced digital applications providing tools, tracking, and measurement, as well as the ability to extend the reach of our sustainability solutions to drive additional market share.
Constellation’s fleet is helping to accelerate the nation’s transition to a carbon-free future with more than 32,355 megawatts of capacity and an annual output that is nearly 90 percent carbon-free. This makes us an important partner to businesses and state and local governments that are setting ambitious carbon-reduction goals and seeking long-term solutions to the climate crisis.
Constellation’s fleet is helping to accelerate the nation’s transition to a carbon-free future with more than 33,094 megawatts of capacity and an annual output that is nearly 90 percent carbon-free. This makes us an important partner to businesses and state and local governments that are setting ambitious carbon-reduction goals and seeking long-term solutions to the climate crisis.
The principles of our sustainable business strategy demonstrate our commitment to a carbon-free future while maintaining a strong balance sheet, advancing our ESG initiatives and investing in clean energy solutions. Power America's Clean Energy Future. We will operate and grow the nation’s largest fleet of clean, zero-emissions generation facilities, with world-class levels of safety, reliability and resiliency.
The principles of our sustainable business strategy demonstrate our commitment to a carbon-free future while maintaining a strong balance sheet, advancing our Environmental, Social, and Governance initiatives and investing in clean energy solutions. Power America's Clean Energy Future. We will operate and grow the nation’s largest fleet of clean, zero-emissions generation facilities, with world-class levels of safety, reliability and resiliency.
During 2022, 2021, and 2020, our nuclear generating facilities achieved capacity factors (a) of 94.8%, 94.5%, and 95.4%, respectively, at ownership percentage. The nuclear capacity factor has been approximately four percentage points better than the industry average annually since 2013.
During 2023, 2022, and 2021, our nuclear generating facilities achieved capacity factors (a) of 94.4%, 94.8%, and 94.5%, respectively, at ownership percentage. The nuclear capacity factor has been approximately four percentage points better than the industry average annually since 2013.
We are also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage. Solid and Hazardous Waste and Environmental Remediation CERCLA authorizes response to releases or threatened releases of hazardous substances into the environment.
We are also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage. 26 Table of Contents Solid and Hazardous Waste and Environmental Remediation CERCLA authorizes response to releases or threatened releases of hazardous substances into the environment.
Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing. See ITEM 1A. RISK FACTORS, ITEM 7.
Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing. 15 Table of Contents See ITEM 1A. RISK FACTORS, ITEM 7.
We have a management team to address environmental compliance and strategy, including the CEO, our Sustainability and Climate Strategy team, and other members of senior management. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process.
We have a management team to address environmental compliance and strategy, including the CEO, and other members of senior management. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process.
Both energy storage and clean hydrogen continue to gain political and business support and are expected to help support net-zero carbon goals. Climate Change Adaptation Our facilities and operations are subject to the global impacts of climate change. Long-term shifts in climactic patterns, such as sustained higher temperatures and sea level rise, may present challenges for our facilities and services.
Both energy storage and clean hydrogen are expected to help support net-zero carbon goals. Climate Change Adaptation Our facilities and operations are subject to the global impacts of climate change. Long-term shifts in climactic patterns, such as sustained higher temperatures and sea level rise, may present challenges for our facilities and services.
We also maintain business interruption insurance for our renewable projects, but not for our other generating stations unless required by contract or financing agreements. We are self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for our insured losses. For additional information regarding property insurance, see ITEM 2.
We also maintain business interruption insurance for our renewable projects, but not for our other generating stations unless required by contract or financing agreements. We are self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for our insured losses. See ITEM 2.
Energy capture represents an energy-based fraction, the numerator of which is the energy produced by the sum of the wind turbines/solar panels in the year, and the denominator of which is the total expected energy to be produced during the year, with adjustments made for certain events that are considered non-controllable, such as force majeure events, serial design-manufacturing equipment failures, and transmission curtailments.
Renewable Energy Capture represents an energy-based fraction, the numerator of which is the energy produced by the sum of the wind turbines, solar panels, and run-of-river hydroelectric operations in the year, and the denominator of which is the total expected energy to be produced during the year, with adjustments made for certain events that are considered non-controllable, such as force majeure events, serial design-manufacturing equipment failures, and transmission curtailments.
Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, we cannot estimate the effect that compliance with the EPA’s 2014 rule will have on the operation of our generating facilities and our consolidated financial statements.
Until the compliance requirements are determined by the applicable state permitting director for each of the seven remaining nuclear stations, on a site-specific basis for each plant, we cannot estimate the effect that compliance with the EPA’s 2014 rule will have on the operation of our generating facilities and our consolidated financial statements.
The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Salem), and Connecticut. We utilize on-site storage capacity at all our stations to store and stage for shipping Class B and Class C LLRW.
The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Salem), and Connecticut. 27 Table of Contents We utilize on-site storage capacity at all our stations to store and stage for shipping Class B and Class C LLRW.
We operate all of these nuclear generating stations, except for the two units at Salem, which are operated by PSEG Nuclear, LLC (an indirect, wholly owned subsidiary of PSEG), and we have consistently operated our nuclear plants at best-in-class levels.
We operate all of these nuclear generating stations, except for the units at Salem and STP, which are operated by PSEG Nuclear, LLC (an indirect, wholly owned subsidiary of PSEG) and STPNOC, respectively. We have consistently operated our nuclear plants at best-in-class levels.
We will continue to manage cash flow volatility through prudent risk management strategies across our business. 19 Table of Contents Growth Opportunities. We continually evaluate growth opportunities aligned with our businesses, assets, and markets leveraging our expertise in those areas and offering durable returns.
We will continue to manage cash flow volatility through prudent risk management strategies across our business. Growth Opportunities. We continually evaluate growth opportunities aligned with our businesses, assets, and markets leveraging our expertise in those areas and offering durable returns.
Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, including contracts sourced from Russia, and contracted fuel fabrication services.
Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, including contracts sourced from Russia, and contracted fuel fabrication services.
Supreme Court decision requiring the EPA to consider costs in determining whether it was appropriate and necessary to regulate power plant emissions of hazardous air pollutants, the EPA issued a supplemental finding that, after considering costs, it remained appropriate and necessary.
In 2016, in response to a U.S. Supreme Court decision requiring the EPA to consider costs in determining whether it was appropriate and necessary to regulate power plant emissions of hazardous air pollutants, the EPA issued a supplemental finding that, after considering costs, it remained appropriate and necessary.
We have inventory in various forms and engage a diverse set of suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term and do not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment, or fabrication services to meet the nuclear fuel requirements of our nuclear units.
We have inventory in various forms and engage a diverse set of domestic and international suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet. We do not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment, or fabrication services to meet the nuclear fuel requirements of our nuclear fleet.
Muddy Run's license expires on December 1, 2055 and is currently being depreciated over the estimated useful life, which corresponds with the available license term.
Muddy Run's license expires on December 1, 2055 and is currently being depreciated over an estimated useful life that corresponds with the available license term.
Our smart utility expense management platform helps customers proactively manage utility costs, understand trends, and develop strategies to optimize spend and drive sustainability objectives. This platform provides new avenues for incremental growth by coupling the opportunities for customer usage optimization with accompanying products and solutions that we can provide to customers.
Our smart utility expense management platform helps customers proactively manage utility costs, understand trends, and develop strategies to optimize spend and drive sustainability objectives, while also providing utility bill payment services. This platform provides new avenues for incremental growth by coupling the opportunities for customer usage optimization with accompanying products and solutions that we can provide to customers.
We achieved an average refueling outage duration of 22 days in both 2021 and 2020, against industry averages of 32 and 34 days, respectively. We manage our scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable supply position for our wholesale and retail power marketing activities.
We achieved an average refueling outage duration of 21 and 22 days in 2022 and 2021, respectively, against industry averages of 40 and 32 days, respectively. We manage our scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable supply position for our wholesale and retail power marketing activities.
An increasing number of corporations are also proactively making commitments to reducing their GHG emissions footprint, either through procuring increasing amounts of clean energy or RECs to offset their carbon footprint over time.
An increasing number of corporations are also proactively making commitments to reducing their GHG emissions footprint, either through procuring increasing amounts of clean energy, such as RECs, EFECs, or emissions offsets, to offset their carbon footprint over time.
A 2022 Rhodium Group study forecasts that as much as 57% of light duty vehicles sold in 2030 will be electric. Electrification of industrial processes, commercial equipment and residential appliances that currently utilize gas and oil as a fuel source will also play a role in increasing the net demand for electricity.
A 2023 Rhodium Group study forecasts as much as 66% of light duty vehicles sold in 2035 will be electric. Electrification of industrial processes, commercial equipment and residential appliances that currently utilize gas and oil as a fuel source will also play a role in increasing the net demand for electricity.
In addition, as soon as reasonably practicable after such materials are furnished to the SEC, we make copies of these documents available to the public free of charge through our website or by contacting our corporate secretary at the applicable address set forth above under "—Corporate Information."
In addition, as soon as reasonably practicable after such materials are furnished to the SEC, we make copies of these documents available to the public free of charge through our website or by contacting our corporate secretary at the applicable address set forth above under "—Corporate Information." ITEM 1B. UNRESOLVED STAFF COMMENTS None.
Expand America's Largest Fleet of Clean Energy Centers. We will leverage and expand our state-of-the-art clean energy assets by exploring co-location of customer load, direct air capture of CO2, and producing clean hydrogen and other sustainable fuels to reduce industrial emissions. Uplift and Strengthen our Communities.
Expand America's Largest Fleet of Clean Energy Centers. We will leverage and expand our state-of-the-art clean energy assets by exploring co-location of customer load, direct air capture of CO2, and, if supported by policy, producing clean hydrogen and other sustainable fuels to reduce industrial emissions. 17 Table of Contents Uplift and Strengthen our Communities.
Where our facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, we may be required to obtain a state water quality certification for those facilities under Clean Water Act section 401.
Our hydroelectric and nuclear facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, we are required to obtain a state water quality certification for those facilities under Clean Water Act section 401.
We serve approximately 2 million total customers, including three-fourths of Fortune 100 companies, and approximately 1.6 million unique residential customers. We are a leader in electric power supply, serving approximately 208 TWhs in 2022 through sales to retail customers and wholesale load auctions to a diverse geographic customer base.
We serve approximately 2 million total customers, including three-fourths of Fortune 100 companies, and approximately 1.7 million unique residential customers. We are a leader in electric power supply, serving approximately 205 TWhs in 2023 through sales to retail customers and wholesale load auctions to a diverse geographic customer base.
We manage various risks around our nuclear fuel requirements in accordance with our fuel procurement policy. The size of our inventory holdings and forward contractual coverage considers our refueling needs across multiple years to protect against supply disruptions and near-term price volatility, while allowing for capital flexibility.
We manage various risks around our nuclear fuel requirements in accordance with our fuel procurement policy limiting our transactions with each supplier to mitigate concentration of risk. The size of our inventory holdings and forward contractual coverage considers our refueling needs across multiple years to protect against supply disruptions and near-term price volatility, while allowing for capital flexibility.
The Nuclear PTC recognizes the contributions of carbon-free nuclear power by providing a federal tax credit of up to $15 per MWh, subject to phase-out, beginning in 2024 and continuing through 2032.
The nuclear PTC recognizes the contributions of carbon-free nuclear power by providing a federal tax credit of up to $15 per MWh, subject to phase-out, beginning in 2024 and continuing through 2032. The nuclear PTC includes annual adjustments for inflation.
The following table illustrates these volumes across our five reportable segments: 13 Table of Contents 2022 Electric Power Supply (TWhs) Served Across Regions (a ) __________ (a) Includes retail load and wholesale load auction volumes only. Electric generation in excess of our total retail and wholesale load would be marketed to the respective ISO in which our facility is located.
The following table illustrates these volumes across our five reportable segments: 2023 Electric Power Supply (TWhs) Served (a ) __________ (a) Includes retail load and wholesale load auction volumes only. Electric generation in excess of our total retail and wholesale load would be marketed to the respective RTO or ISO in which our facility is located.
As of December 31, 2022, we had approximately 91,500 SNF assemblies (22,400 tons) stored on site in SNF pools or dry cask storage that includes SNF assemblies at Zion Station, for which we retain ownership and responsibility for the decommissioning of the Zion Independent Spent Fuel Storage Installation. All our nuclear sites have on-site dry cask storage.
As of December 31, 2023, we had approximately 93,600 SNF assemblies (22,900 tons) stored on site in SNF pools or dry cask storage that includes SNF assemblies at Zion Station, for which we retain ownership and responsibility for the decommissioning of the Zion Independent Spent Fuel Storage Installation. All our nuclear sites have on-site dry cask storage.
We expect widespread electrification, hydrogen production, and direct air capture could result in U.S. electricity demand to more than double from what it is today by 2050.
We expect widespread electrification, hydrogen production, data centers, and direct air capture could cause U.S. electricity demand to more than double from what it is today by 2050.
Retail customer renewal rates have been strong over the last six years across C&I power customer groups, with an average contract term of approximately two years and customer duration of more than six years, with many customers well beyond these metrics.
Retail customer renewal rates have been strong over the last seven years across C&I power customer groups, with average contract terms of approximately two years and customer duration of approximately six years, with many customers well beyond these metrics.
As of December 31, 2022, we wholly own all our nuclear generating stations, except for undivided ownership interests in four jointly owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), Salem (42.59% ownership), and Nine Mile Point Unit 2 (82% ownership), which are consolidated in our consolidated financial statements relative to our proportionate ownership interest in each unit.
As of December 31, 2023, we wholly own all our nuclear generating stations, except for undivided ownership interests in five jointly owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), Salem (42.59% ownership), Nine Mile Point Unit 2 (82% ownership), and STP 44% ownership), that are included in our consolidated financial statements relative to our proportionate ownership interest in each unit.
Growing awareness of climate change and green energy helps drive customer interest in value-add services and products around their energy usage, such as residential rooftop solar, EV charging, smart, energy-efficient home technologies, and the ability to choose 100 percent clean power 24 hours a day, 365 days a year in competitive retail energy markets.
Growing awareness of climate change and green energy helps drive customer interest in value-add services and products around their energy usage, such as solar, behind-the-meter storage, EV charging, and the ability to choose 100 percent clean power 24 hours a day, 365 days a year in competitive retail energy markets.
The following table presents employee information, including information about CBAs, as of December 31, 2022: Total Employees Covered by CBAs Number of CBAs CBAs New and Renewed in 2022 (a) Total Employees Under CBAs New and Renewed in 2022 3,342 21 1 74 __________ (a) Does not include CBAs that were extended in 2022 while negotiations are ongoing for renewal.
The following table presents employee information, including information about CBAs, as of December 31, 2023: Total Employees Covered by CBAs Number of CBAs CBAs New and Renewed in 2023 (a) Total Employees Under CBAs New and Renewed in 2023 3,343 21 4 410 __________ (a) Does not include CBAs that were extended in 2023 while negotiations are ongoing for renewal.
In addition to larger-scale CORe offerings, we offer a range of sustainability solutions to customers (RECs, EFECs, RINs, RNG, carbon offsets, hourly carbon-free energy matching, etc.) to support their energy needs during the transition to a carbon-free energy ecosystem. In addition to sustainability products and services, data and analytics have also become increasingly important for our customers.
In addition to larger-scale CORe+ offerings and Hourly CFE, we offer a range of sustainability solutions to customers (e.g., RECs, CORe, EFECs, RINs, RNG, carbon offsets, etc.) to support their energy needs during the transition to a carbon-free energy ecosystem. 14 Table of Contents In addition to sustainability solutions, data and analytics have also become increasingly important for our customers.
We may pursue growth opportunities that optimize our core business or expand upon our strengths, including, but not limited to the following: • Opportunistic carbon-free energy acquisitions, particularly nuclear plants with supportive policy, • Create new value from the existing fleet through repowering, co-location and other opportunities, • Grow sustainability products and services for our customers focused on clean energy, efficiency, storage and electrification; help our C&I customers develop and meet sustainability targets, • Produce clean hydrogen using our carbon-free fleet, • Engagement with the technology and innovation ecosystem through continued partnerships with national labs, universities, startups, and research institutions, and • Explore advanced nuclear technology for investment and participation via advisory services to maintain our leadership position as stewards of a carbon-free energy future.
We may pursue growth opportunities that optimize our core business or expand upon our strengths, including, but not limited to the following: • Opportunistic carbon-free energy acquisitions, particularly nuclear plants with supportive policy, • Create new value from the existing fleet through nuclear uprates, repowering of renewables, co-location of customer load (including hydrogen with supportive policy), and other opportunities, • Grow sustainability solutions for our customers focused on clean energy, efficiency, storage and electrification; help our C&I customers develop and meet sustainability targets, • Engagement with the technology and innovation ecosystem through continued partnerships with national labs, universities, startups, and research institutions, and • Continue to monitor opportunities to participate in advanced nuclear to maintain our leadership position as stewards of a carbon-free energy future.
Our Scope 1 and 2 GHG emissions in 2021 were 8.3 million metric tons carbon dioxide equivalent, of which 8.0 million metric tons were from our natural gas and oil fueled generation fleet, significantly less than our peers with similar volume of power generation.
Our Scope 1 and 2 market-based GHG emissions in 2022 were 9.2 million metric tons carbon dioxide equivalent, of which 8.6 million metric tons were from our natural gas and oil fueled generation fleet, significantly less than our peers with similar volume of power generation.
RISK FACTORS, for additional information. 26 Table of Contents We conduct seasonal readiness reviews at our power plants to ensure availability of fuel supplies and equipment performance before entering the summer and winter seasons and we consider and review national climate assessments to inform our longer-term planning.
We conduct seasonal readiness reviews at our power plants to ensure availability of fuel supplies and equipment performance before entering the summer and winter seasons and we consider and review national climate assessments to inform our longer-term planning.
Our generation fleet of nuclear, hydro, wind, natural gas, and solar generation facilities has the generating capacity to power the equivalent of 15 million homes, producing 11 percent of the carbon-free energy in the United States.
Our generation fleet of nuclear, hydro, wind, and solar generation facilities has the generating capacity to power the equivalent of 16 million homes, producing about 10 percent of the carbon-free energy in the United States.
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.
On August 16, 2022, 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.
We believe our operations could be significantly affected by the physical risks of climate change. See ITEM 1A.
We believe our operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS, for additional information.
(c) In February 2022, the NRC issued an order related to its review of our subsequent license renewal application for Peach Bottom and the NRC directed its staff to change the expiration dates for the licenses back to 2033 and 2034.
(c) In February 2022, the NRC issued an order related to its review of our subsequent license renewal application for Peach Bottom and the NRC directed its staff to change the expiration dates for the licenses back to 2033 and 2034. We expect that the license expiration dates will be restored to 2053 and 2054, respectively.
However, the final rule does not mandate cooling towers and allows state permitting directors to require alternative, less costly technologies and/or operational measures, based on a site-specific assessment of the feasibility, costs, and benefits of available options.
However, the final rule does not mandate cooling towers and allows state permitting directors to require alternative, less costly technologies and/or operational measures, based on a site-specific assessment of the feasibility, costs, and benefits of available options. There is no regulatory established timeline for NPDES permit renewals.
Units that are not currently operational are not captured. (b) Does not reflect Grand Prairie Generating Station (Gas/Other), located in Alberta, Canada. 8 Table of Contents We have five reportable segments, as described in the table below, representing the different geographical areas in which our owned generating resources are located and our customer-facing activities are conducted.
(b) Does not reflect Grand Prairie Generating Station (Gas/Other), located in Alberta, Canada. 7 Table of Contents We have five reportable segments, as described in the table below, representing the different geographic regions in which our owned generating resources are located and our customer-facing activities are conducted.
We have ownership interests in 13 nuclear generating stations currently in service, consisting of 23 units.
We have ownership interests in 14 nuclear generating stations currently in service, consisting of 25 units.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeA security breach, including physical or electronic break-ins, computer viruses, malware, attacks by hackers, ransomware attacks, phishing attacks, supply chain attacks, breaches due to employee error or misconduct and other similar breaches, of our physical assets or information systems, or those of our competitors, vendors, 39 Table of Contents business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor and employee data, trading or other confidential data.
Biggest changeA security breach, including, but not limited to, physical or electronic intrusions, computer viruses, malware, attacks by cyber criminals or nation state threat actors, ransomware attacks, phishing attacks, supply chain attacks, third-party breaches, and other similar breaches of our physical assets or information systems, or those of our competitors, vendors, business partners and interconnected entities in RTOs, ISOs, and other energy markets, or regulators have the potential to disrupt our business and result in harm to the Company.
Such risks, which could negatively affect our consolidated financial statements, fall primarily under the categories below: Risks related to market and financial factors primarily include: • the price of fuels, in particular the price of natural gas, which affects power prices, • the generation resources in the markets in which we operate, • our ability to operate our generating assets, • our ability to access capital markets, • the impacts of on-going competition, and • emerging technologies and business models, including those related to climate change mitigation and transition to a low-carbon economy.
Such risks, which could negatively affect our consolidated financial statements, fall primarily under the categories below: Risks related to market and financial factors primarily include: • the price of fuels, in particular the price of natural gas, which affects power prices, • the generation resources in the markets in which we operate, • the design of power markets, • our ability to operate our generating assets, • our ability to access capital markets, • the impacts of on-going competition, and • emerging technologies and business models, including those related to climate change mitigation and transition to a low-carbon economy.
We periodically perform analyses to better understand how climate change could affect our facilities and operations. We primarily operate in the Midwest and East Coast of the United States, areas that have historically been prone to various types of severe weather events, and as such we have well-developed response and recovery programs based on these historical events.
We periodically perform analyses to better understand how climate change could affect our facilities and operations. We primarily operate in the Midwest, East Coast of the United States, and Texas areas that have historically been prone to various types of severe weather events, and as such we have well-developed response and recovery programs based on these historical events.
If this were to happen, identifying and correcting the causes could require significant time and expense. We could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, we could lose revenue and incur increased purchased power and fuel expense to meet supply commitments.
If this were to happen, identifying and correcting the causes could require significant time and expense. We could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, we could lose revenue and incur increased purchased power costs and fuel expense to meet supply commitments.
Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit. Cost of Fuel. We depend on nuclear fuel, natural gas and oil to operate most of our generating facilities.
Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit. Cost and Availability of Fuel. We depend on nuclear fuel, natural gas and oil to operate most of our generating facilities.
We also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction regulation or legislation becomes 37 Table of Contents effective at the federal and/or state levels, we could incur costs to further limit the GHG emissions from our operations or otherwise comply with applicable requirements.
We also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction regulation or legislation becomes 40 Table of Contents effective at the federal and/or state levels, we could incur costs to further limit the GHG emissions from our operations or otherwise comply with applicable requirements.
Each of these factors could affect our consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital 31 Table of Contents expenditures, and potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Each of these factors could affect our consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital 34 Table of Contents expenditures, and potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
For the year ended December 31, 2021, a pre-tax charge of $193 million was recorded in the Consolidated Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended.
For the year ended December 31, 2021, a pre-tax charge of $193 million was recorded in the Consolidated Statement of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended.
Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions.
Such initiatives could involve significant risks and uncertainties, including distraction of 44 Table of Contents management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions.
We could also lose operating revenues and incur increased purchased power and fuel expense to meet our supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, require a substantial 36 Table of Contents increase in capital expenditures, result in increased operating costs or render the project uneconomic.
We could also lose operating revenues and incur increased purchased power and fuel expense to meet our supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, require a substantial increase in capital expenditures, result in increased operating costs or render the project uneconomic.
In the spot markets, we are exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. We are also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties.
In the spot markets, we are exposed to risk as a result of default sharing 37 Table of Contents mechanisms that exist within certain markets, primarily RTOs and ISOs. We are also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties.
Risks Related to Market and Financial Factors We are exposed to price volatility associated with both the wholesale and retail power markets and the procurement of nuclear, natural gas and oil. 30 Table of Contents We are exposed to commodity price risk for natural gas and the unhedged portion of our generation portfolio.
Risks Related to Market and Financial Factors We are exposed to price volatility associated with both the wholesale and retail power markets and the procurement of nuclear fuel, natural gas and oil. 33 Table of Contents We are exposed to commodity price risk for natural gas and the unhedged portion of our generation portfolio.
If circumstances changed such that there was an inability to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if we no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected.
If circumstances changed such that there was an inability to continue to make contributions to the trust funds of the former PECO or STP units based on amounts collected from utility customers, or if we no longer had recourse to collect additional amounts from the respective utility customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to these units could be negatively affected.
A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by us, could cause the NRC to initiate such actions. 35 Table of Contents Spent Nuclear Fuel Storage.
A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by us, could cause the NRC to initiate such actions. Spent Nuclear Fuel Storage.
Further, our nuclear operations produce various types of nuclear waste materials, including SNF. The approval of a national repository for the storage of SNF and the timing of that facility opening, will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse us for these costs.
Our nuclear operations produce various types of nuclear waste materials, including SNF. The approval of a national repository for the storage of SNF and the timing of that facility opening, 38 Table of Contents will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse us for these costs.
We could be negatively affected by the impacts of weather. Our operations are affected by weather, which impacts demand for electricity and natural gas, the price of energy commodities, as well as operating conditions.
We could be negatively affected by the impacts of weather. 36 Table of Contents Our operations are affected by weather, which impacts demand for electricity and natural gas, the price of energy commodities, as well as operating conditions.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the February 2021 extreme cold weather event and Texas-based generating asset outages. Risks Related to Legislative, Regulatory, and Legal Factors Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets.
See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the February 2021 extreme cold weather event and Texas-based generating asset outages. Risks Related to Legislative, Regulatory, and Legal Factors Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets.
ITEM 1A. RISK FACTORS 29 Table of Contents We operate in a complex market and regulatory environment that involves significant risks, many of which are beyond our direct control.
ITEM 1A. RISK FACTORS We operate in a complex market and regulatory environment that involves significant risks, many of which are beyond our direct control.
We are in the process of creating our own, or engaging third parties to provide, systems and services to replace many of the systems and services that Exelon currently provides to us.
We are in the process of creating our own, or engaging third parties to provide, systems and services to replace many of the systems and services that Exelon currently 45 Table of Contents provides to us.
In addition, our retail sales subject us to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations.
In addition, our retail sales subject us to credit risk through competitive electricity and natural gas supply activities to serve C&I companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations.
For nuclear plants not operated and not wholly owned by us, from which we receive a portion of the plants’ output, our results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants.
For nuclear plants not operated and not wholly owned by us, from which we receive a portion of the plants’ output, our results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. We do not procure the fuel for the sites we do not operate.
Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.
Risks related to legislative, regulatory, and legal factors primarily include changes to, and compliance with, the laws and regulations that govern: • the design of power markets, • the renewal of permits and operating licenses, • environmental and climate policy, and • tax policy.
Risks related to legislative, regulatory, and legal factors primarily include changes to, and compliance with, the laws and regulations that govern: • the renewal of operating licenses, • environmental and climate policy, and • tax policy.
In addition, we have exposure to worldwide financial markets, including Europe, Canada and Asia. Disruptions in these markets could reduce or restrict our ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2022, approximately 38%, 13%, and 19% of our available credit facilities were with European, Canadian and Asian banks, respectively.
In addition, we have exposure to worldwide financial markets, including Europe, Canada and Asia. Disruptions in these markets could reduce or restrict our ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2023, approximately 37%, 12%, and 17% of our available credit facilities were with European, Canadian and Asian banks, respectively.
If a significant breach were to occur, our reputation could be negatively affected, customer confidence in us or others in the industry could be diminished, or we could be subject to legal claims, loss of revenues, increased costs or operations shutdown.
Furthermore, if a significant security breach were to occur, our reputation could be negatively affected, customer confidence in us or others in the industry could be diminished, or we could be subject to legal claims, loss of revenues, increased costs, regulatory penalties, or operational shutdown.
In addition, drought-like conditions limiting water usage could impact our ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause us to seek additional capacity at a time when markets are weak.
In addition, drought-like conditions limiting water usage could impact our ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause us to seek additional replacement supply at a time when supply is constrained.
One or both events could adversely affect available liquidity and, in the case of a rating downgrade, borrowing and credit support costs. 32 Table of Contents See ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Liquidity and Capital Resources – Credit Matters and Cash Requirements – Security Ratings for additional information regarding the potential impacts of credit downgrades on our cash flows.
One or both events could adversely affect available liquidity and, in the case of a rating downgrade, borrowing and credit support costs. 35 Table of Contents See ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Liquidity and Capital Resources – Credit Matters and Cash Requirements – Security Ratings and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the potential impacts of credit downgrades on our cash flows.
Any changes to the PECO regulatory agreements could impact our ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to our consolidated financial statements could be material.
Any changes to the utilities' regulatory agreements could impact our ability to offset decommissioning-related activities for these units within the Consolidated Statements of Operations and Comprehensive Income, and the impact to our consolidated financial statements could be material.
We have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets, including several of the Exelon utilities in connection with our absorption of their former generating assets.
We have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets, including several of the Exelon utilities in connection with our absorption of their former generating assets. We could incur substantial costs to fulfill our obligations under these indemnities.
Risks related to operational factors primarily include: • changes in the global climate could produce extreme weather events, which could put our facilities at risk, and such changes could also affect the levels and patterns of demand for energy and related services, • the safe, secure and effective operation of our nuclear facilities and the ability to effectively manage the associated decommissioning obligations, • the ability of energy transmission and distribution companies to maintain the reliability, resiliency and safety of their energy delivery systems, which could affect our ability to deliver energy to our customers and affect our operating costs, and • physical and cyber security risks for us as an owner-operator of generation facilities and as a participant in commodities trading.
Risks related to operational factors primarily include: • changes in the global climate could produce extreme weather events, which could put our facilities at risk, and such changes could also affect the levels and patterns of demand for energy and related services, • the safe, secure and effective operation of our nuclear facilities and the ability to effectively manage the associated decommissioning obligations, and • physical and cybersecurity risks for us as an owner-operator of generation facilities and as a participant in commodities trading.
In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for our continued operation, particularly the cooling of generating units. The impact that potential terrorist attacks could have on the industry and on us is uncertain.
In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for our continued operation, particularly the cooling of generating units.
In addition, we maintain a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations.
In addition, we maintain a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.
The impacts of significant economic downturns on our retail customers, such as less demand for products and services provided by commercial and industrial customers, could result in an increase in the number of uncollectible customer balances and related expense. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information on our credit risk.
The impacts of significant economic downturns on our retail customers, such as less demand for products and services provided by C&I customers, could result in an increase in the number of uncollectible customer balances and related expense. See ITEM 7A.
We are exposed to other credit risks in the power markets that are beyond our control. We have entered into various agreements with counterparties that require those counterparties to reimburse us and hold us harmless against specified obligations and claims.
We could incur substantial costs in the event of non-performance by third parties under indemnification agreements. We are exposed to other credit risks in the power markets that are beyond our control. We have entered into various agreements with counterparties that require those counterparties to reimburse us and hold us harmless against specified obligations and claims.
We could incur substantial costs to fulfill our obligations under these indemnities. 34 Table of Contents In the bilateral markets, we are exposed to the risk that counterparties that owe us money or are obligated to purchase energy or fuel from us, will not perform under their obligations for operational or financial reasons.
In the bilateral markets, we are exposed to the risk that counterparties that owe us money or are obligated to purchase energy or fuel from us, will not perform under their obligations for operational or financial reasons.
This could include opportunistic carbon-free energy acquisitions, creating new value from our existing fleet through repowering, co-location and the production of hydrogen, growing sustainability products and services for our customers, and investment opportunities in other emerging technologies and innovation.
This could include opportunistic carbon-free energy acquisitions, creating new value from our existing fleet through nuclear uprates, renewable repowerings, co-location of customer load, growing sustainability solutions for our customers, and investment opportunities in other emerging technologies and innovation.
Accordingly, during the period in which the terms of those agreements were prepared, we did not have an independent Board of Directors or a management team that was independent of Exelon.
Accordingly, during the period in which the terms of those agreements were prepared, we did not have an independent Board of Directors or a management team that was independent of Exelon. As a result, the terms of those agreements may not reflect terms that would have resulted from negotiations between unaffiliated third parties.
The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, could arise. We are particularly affected due to the specialized knowledge required of the technical and support employees for generation operations.
In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, could arise. We are particularly affected due to the specialized knowledge required of the technical and support employees for generation operations.
We could be subject to adverse publicity and reputational risks, which make us vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences. We could be the subject of public criticism.
Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict existing business activities. We could be subject to adverse publicity and reputational risks, which make us vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences. We could be the subject of public criticism.
As a result, the terms of those agreements may not reflect terms that would have resulted from negotiations between unaffiliated third parties. 41 Table of Contents Exelon may fail to perform under various transaction agreements that were executed as part of the separation, which could cause us to incur expenses or losses we would not otherwise incur.
Exelon may fail to perform under various transaction agreements that were executed as part of the separation, which could cause us to incur expenses or losses we would not otherwise incur.
See Note 1 — Basis of Presentation and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Legal proceedings could result in a negative outcome, which we cannot predict. We are involved in legal proceedings, claims and litigation arising from our business operations.
Legal proceedings could result in a negative outcome, which we cannot predict. We are involved in legal proceedings, claims and litigation arising from our business operations. Our material legal proceedings, claims and litigation are summarized in Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Risks related to our separation from Exelon primarily include: • challenges to achieving the benefits of separation, including the need to replicate certain services provided by Exelon (e.g. information technology), which will require additional resources and expense, • performance by Exelon and us under the transaction agreements, including indemnification responsibilities tied to the allocation of businesses and liabilities, and • limitations on future capital-raising or strategic transactions during the two-year period following the distribution arising from the need to protect the tax-free treatment of the distribution.
Risks related to our separation from Exelon primarily include: • replicate certain services provided by Exelon (e.g., information technology), which will require additional resources and expense, and • performance by Exelon and us under the transaction agreements, including indemnification responsibilities tied to the allocation of businesses and liabilities.
Our fleet of power plants and the transmission infrastructure to which they are connected could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs.
Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact our results of operations, ability to raise capital, and future growth. 43 Table of Contents Our fleet of power plants and the transmission infrastructure to which they are connected could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Critical Accounting Policies and Estimates, Note 8 — Property, Plant, and Equipment and Note 12 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information on long-lived asset impairments. We could incur substantial costs in the event of non-performance by third-parties under indemnification agreements.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Critical Accounting Policies and Estimates, Note 1 — Basis of Presentation, Note 8 — Property, Plant, and Equipment, Note 12 — Asset Impairments, and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information on long-lived asset impairments.
Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.7 billion limit for a single incident. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear insurance.
Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $16.2 billion limit for a single incident. 41 Table of Contents See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear insurance. Decommissioning obligation and funding.
Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by us. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the license renewal for the Conowingo hydroelectric project.
Similar 39 Table of Contents effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by us.
Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result. Furthermore, in the future, such insurance may not be available on commercially reasonable terms, or at all.
Although we maintain insurance coverage for cyber events, the amount and scope of insurance maintained against losses resulting from a significant event or security breach may not be sufficient to cover losses or otherwise adequately compensate for any business disruptions that could result.
Our performance could be negatively affected if we fail to attract and retain an appropriately qualified workforce. Certain events, such as the separation transaction, an employee strike, loss of employees, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for us.
Certain events, such as an employee strike, loss of employees, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for us. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development.
Nuclear major incident risk and insurance. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by us or owned by others, could exceed our resources, including insurance coverage.
Any resulting liability from a nuclear plant major incident within the United States, owned or operated by us or owned by others, could exceed our resources, including insurance coverage. We are a member of an industry mutual insurance company, NEIL, which provides property and accidental outage insurance for our nuclear operations.
Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered. An impairment would require us to reduce the carrying value of the long-lived asset to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7.
An impairment would require us to reduce the carrying value of the long-lived asset and goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7.
All these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment. Risks Related to Our Separation from Exelon We may not achieve some or all the expected benefits of the separation, and the separation may materially adversely affect our business.
All these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment. Risks Related to Our Separation from Exelon The terms in our agreements with Exelon could be less beneficial than the terms we may have otherwise received from unaffiliated third parties.
Our consolidated financial statements could be negatively affected if we were unable to effectively manage our capital projects or raise the necessary capital. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Liquidity and Capital Resources for additional information regarding our potential future capital expenditures.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Liquidity and Capital Resources for additional information regarding our potential future capital expenditures. Our performance could be negatively affected if we fail to attract and retain an appropriately qualified workforce.
See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. We are subject to physical security and cybersecurity risks. We face physical security and cybersecurity risks.
See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. We are subject to evolving physical security and cybersecurity risks. Threat actors continue to seek to exploit potential vulnerabilities in the energy sector associated with protection of sensitive and confidential information, grid infrastructure and other energy infrastructures.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates.
See Note 7 — Early Plant Retirements and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates.
These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities.
These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Basis of Presentation and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
See Note 3 — Regulatory Matters and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. Fundamental changes in regulations or other adverse legislative actions affecting our business would require changes in our business planning models and operations.
See Note 3 — Regulatory Matters and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. NRC actions could negatively affect the operations and profitability of our nuclear generating fleet. Regulatory Risk.
We cannot predict when or whether legislative and regulatory proposals could become law or what their effect would be. NRC actions could negatively affect the operations and profitability of our nuclear generating fleet. Regulatory Risk.
Fundamental changes in regulations or other adverse legislative actions affecting our business would require changes in our business planning models and operations. We cannot predict when or whether legislative and regulatory proposals could become law or what their effect would be.
Additionally, poor operating performance at nuclear plants not owned by us could result in increased regulation and reduced public support for nuclear-fueled energy. Closure of generating plants owned by others, or extended interruptions of generating plants or failure of transmission lines, could adversely affect transmission systems and the sale and delivery of electricity in markets served by us.
The operator's nuclear fuel procurement plan could impact our results of operations. Additionally, poor operating performance at nuclear plants not owned by us could result in increased regulation and reduced public support for nuclear-fueled energy.
Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned by us or others, could result in increased regulation and reduced public support for nuclear-fueled energy. 38 Table of Contents As required by the Price-Anderson Act, we carry the maximum available amount of nuclear liability insurance, $450 million for each operating site.
Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by us. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned by us or others, could result in increased regulation and reduced public support for nuclear-fueled energy.
Our business is capital intensive and requires significant investments in electric generating facilities. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond our control, and could require significant expenditures to remedy.
Our business is capital intensive, and our assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability. Our business is capital intensive and requires significant investments in electric generating facilities.
In addition, our costs for the operation of these systems may be higher than the amounts reflected in our historical financial statements. We may not be able to engage in desirable strategic transactions or capital-raising following the separation.
In addition, our costs for the operation of these systems may be higher than the amounts reflected in our historical financial statements. ITEM 4. MINE SAFETY DISCLOSURES Not Applicable. PART II
We could be negatively affected by challenges to tax positions taken, tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions. We are required to make judgments in order to estimate our obligations to taxing authorities.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the license renewal for the Conowingo hydroelectric project. We could be negatively affected by challenges to tax positions taken, tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions.
While we, through PECO, have recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), we have no recourse to collect additional amounts from utility customers for any of our other nuclear units if there is a shortfall of funds necessary for decommissioning.
We have recourse to collect additional amounts from utility customers through PECO (subject to certain limitations and thresholds) for former PECO units and through CenterPoint Energy Houston Electric and AEP Texas for STP units.
If we are required to arrange for the safe and permanent disposal of spent fuel beyond current expectations, this could lead to substantial expense or capital expenditures. For plants operated but not wholly owned by us, we could also incur liability to our co-owners.
For plants operated but not wholly owned by us, we could also incur liability to our co-owners.
Long-lived assets – principally, generation assets – represent the single largest asset class on our Consolidated Balance Sheets. We evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment may exist.
We evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment may exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered.
By comparison, the estimated impact reduced our overall Net loss by approximately $50 million for the year ended December 31, 2022, see Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. Long-lived assets and other assets could become impaired.
See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. Long-lived assets, goodwill, and other assets could become impaired. Long-lived assets – principally, generation assets – represent the single largest asset class on our Consolidated Balance Sheets. In addition, we have a material goodwill balance as of December 31, 2023.
The risk of these system-related events and security breaches occurring continues to intensify, and while we have not directly experienced a material breach or disruption to our network or information systems or our operations to-date, such attacks continue to increase in sophistication and frequency, and we may be unable to prevent all such attacks in the future.
While we have not experienced a material breach or disruption to our network or information systems or our operations to date, future attacks may negatively impact our business, reputation, or financial results.
In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by us or our business operations and could adversely affect our consolidated financial statements. Our employees, contractors, customers and the general public could be exposed to a risk of injury due to the nature of the energy industry.
There can be no assurance that such insurance will be available on commercially reasonable terms, in the future. In addition, new or updated security regulations or new vulnerabilities identified by security researchers, third-party suppliers, or threat actors could require changes in current measures taken by security or our business operations and could adversely affect our consolidated financial statements.
Removed
Our results were negatively affected by the impacts of COVID-19 in 2020 and future pandemics or other significant health issues could also adversely affect our results. 33 Table of Contents COVID-19 has previously disrupted economic activity in our markets and negatively affected our results of operations.
Added
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on our credit risk.
Removed
The estimated impact of COVID-19 to our Net income was approximately $170 million for the year ended December 31, 2020 and was not material for the years ended December 31, 2021 and 2022. Any future widespread pandemic or other local or global health issue could adversely affect customer demand and our ability to operate our generation assets.
Added
We assess goodwill for impairment at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Changes in significant assumptions, including discount rates, energy prices, projected operating costs, and cash flows could potentially result in future impairments of goodwill.
Removed
The approval of a national repository for the storage of SNF and the timing of that facility opening, will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse us for these costs.
Added
The PTC benefiting existing nuclear plants included in the IRA (starting January 1, 2024) continues to be the subject of additional guidance issued from the U.S. Treasury and IRS, which may negatively impact the amount of benefits we ultimately receive with respect to some of our units.
Removed
The material ones are summarized in Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict existing business activities.
Added
We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters.
Removed
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect our ability to decommission fully our nuclear units. We cannot predict whether in the future a fee for SNF disposal may be reestablished or to what extent.
Added
If we are required to arrange for the safe and permanent disposal of SNF beyond current expectations, this could lead to substantial expense or capital expenditures. See "NRC actions could negatively affect the operations and profitability of our nuclear generating fleet" above for additional information on the storage of SNF.
Removed
We are a member of an industry mutual insurance company, NEIL, which provides property and accidental outage insurance for our nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by us.
Added
Closure of generating plants owned by others, or extended interruptions of generating plants or failure of transmission lines, could adversely affect transmission systems and the sale and delivery of electricity in markets served by us. Nuclear major incident risk and insurance. The consequences of a major incident could be severe and include loss of life and property damage.

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Item 2. Properties

Properties — owned and leased real estate

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Biggest changePROPERTIES The following table presents our interests in net electric generating capacity by station at December 31, 2022: Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Midwest Braidwood Braidwood, IL 2 Uranium Base-load 2,386 Byron Byron, IL 2 Uranium Base-load 2,347 (e) LaSalle Seneca, IL 2 Uranium Base-load 2,320 Dresden Morris, IL 2 Uranium Base-load 1,845 (e) Quad Cities Cordova, IL 2 75 Uranium Base-load 1,403 (f) Clinton Clinton, IL 1 Uranium Base-load 1,080 Michigan Wind 2 Sanilac Co., MI 50 51 (g) Wind Intermittent 46 (f) Beebe Gratiot Co., MI 34 51 (g) Wind Intermittent 42 (f) Michigan Wind 1 Huron Co., MI 46 51 (g) Wind Intermittent 35 (f) Harvest 2 Huron Co., MI 33 51 (g) Wind Intermittent 30 (f) Harvest Huron Co., MI 31 51 (g) Wind Intermittent 26 (f) Beebe 1B Gratiot Co., MI 21 51 (g) Wind Intermittent 26 (f) Blue Breezes Faribault Co., MN 2 Wind Intermittent 3 CP Windfarm Faribault Co., MN 2 51 (g) Wind Intermittent 2 (f) Southeast Chicago Chicago, IL 8 Gas Peaking 296 (h) Clinton Battery Storage Blanchester, OH 1 Energy Storage Peaking 5 Total Midwest 11,892 Mid-Atlantic Limerick Sanatoga, PA 2 Uranium Base-load 2,315 Calvert Cliffs Lusby, MD 2 Uranium Base-load 1,789 Peach Bottom Delta, PA 2 50 Uranium Base-load 1,324 (f) Salem Lower Alloways Creek Township, NJ 2 42.59 Uranium Base-load 993 (f) Conowingo Darlington, MD 11 Hydroelectric Base-load 572 Criterion Oakland, MD 28 51 (g) Wind Intermittent 36 (f) 43 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Fair Wind Garrett County, MD 12 Wind Intermittent 30 Fourmile Ridge Garrett County, MD 16 51 (g) Wind Intermittent 20 (f) Solar Horizons Emmitsburg, MD 1 51 (g) Solar Intermittent 8 (f) Solar New Jersey 3 Middle Township, NJ 5 51 (g) Solar Intermittent 1 (f) Muddy Run Drumore, PA 8 Hydroelectric Intermediate 1,070 Eddystone 3, 4 Eddystone, PA 2 Oil/Gas Peaking 760 Perryman Aberdeen, MD 5 Oil/Gas Peaking 404 Croydon West Bristol, PA 8 Oil Peaking 391 Handsome Lake Kennerdell, PA 5 Gas Peaking 268 Richmond Philadelphia, PA 2 Oil Peaking 98 Philadelphia Road Baltimore, MD 4 Oil Peaking 61 Eddystone Eddystone, PA 4 Oil Peaking 60 Delaware Philadelphia, PA 4 Oil Peaking 56 Southwark Philadelphia, PA 4 Oil Peaking 52 Falls Morrisville, PA 3 Oil Peaking 51 Moser Lower Pottsgrove Twp., PA 3 Oil Peaking 51 Chester Chester, PA 3 Oil Peaking 39 Schuylkill Philadelphia, PA 2 Oil Peaking 30 Salem Lower Alloways Creek Township, NJ 1 42.59 Oil Peaking 16 (f) Total Mid-Atlantic 10,495 ERCOT Whitetail Webb County, TX 57 51 (g) Wind Intermittent 47 (f) Sendero Jim Hogg and Zapata County, TX 39 51 (g) Wind Intermittent 40 (f) Colorado Bend II Wharton, TX 3 Gas Intermediate 1,143 Wolf Hollow II Granbury, TX 3 Gas Intermediate 1,115 Handley 3 Fort Worth, TX 1 Gas Intermediate 395 Handley 4, 5 Fort Worth, TX 2 Gas Peaking 870 Total ERCOT 3,610 New York Nine Mile Point Scriba, NY 2 (i) Uranium Base-load 1,675 (f) FitzPatrick Scriba, NY 1 Uranium Base-load 842 Ginna Ontario, NY 1 Uranium Base-load 576 Total New York 3,093 Other Antelope Valley Lancaster, CA 1 Solar Intermittent 242 44 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Bluestem Beaver County, OK 60 51 (g)(j) Wind Intermittent 101 (f) Shooting Star Kiowa County, KS 65 51 (g) Wind Intermittent 53 (f) Sacramento PV Energy Sacramento, CA 4 51 (g) Solar Intermittent 15 (f) Bluegrass Ridge King City, MO 27 51 (g) Wind Intermittent 29 (f) Conception Barnard, MO 24 51 (g) Wind Intermittent 26 (f) Cow Branch Rock Port, MO 24 51 (g) Wind Intermittent 26 (f) Mountain Home Glenns Ferry, ID 20 51 (g) Wind Intermittent 21 (f) High Mesa Elmore Co., ID 19 51 (g) Wind Intermittent 20 (f) Echo 1 Echo, OR 21 50.49 (g) Wind Intermittent 17 (f) Cassia Buhl, ID 13 51 (g) Wind Intermittent 14 (f) Wildcat Lovington, NM 13 51 (g) Wind Intermittent 14 (f) Echo 2 Echo, OR 9 51 (g) Wind Intermittent 9 (f) Tuana Springs Hagerman, ID 8 51 (g) Wind Intermittent 9 (f) Greensburg Greensburg, KS 10 51 (g) Wind Intermittent 6 (f) Three Mile Canyon Boardman, OR 6 51 (g) Wind Intermittent 5 (f) Loess Hills Rock Port, MO 4 Wind Intermittent 5 Denver Airport Solar Denver, CO 1 51 (g) Solar Intermittent 2 (f) Mystic 8, 9 Charlestown, MA 6 Gas Intermediate 1,413 (e) Hillabee Alexander City, AL 3 Gas Intermediate 753 Wyman 4 Yarmouth, ME 1 5.9 Oil Intermediate 34 (f) West Medway II West Medway, MA 2 Oil/Gas Peaking 191 West Medway West Medway, MA 3 Oil Peaking 124 Grand Prairie Alberta, Canada 1 Gas Peaking 105 Framingham Framingham, MA 3 Oil Peaking 31 Total Other 3,265 Total 32,355 __________ (a) All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors.
Biggest changePROPERTIES The following table presents our interests in net electric generating capacity by station at December 31, 2023: Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Midwest Braidwood Braidwood, IL 2 Uranium Base-load 2,386 Byron Byron, IL 2 Uranium Base-load 2,347 (e) LaSalle Seneca, IL 2 Uranium Base-load 2,320 Dresden Morris, IL 2 Uranium Base-load 1,845 (e) Quad Cities Cordova, IL 2 75 Uranium Base-load 1,403 Clinton Clinton, IL 1 Uranium Base-load 1,092 Michigan Wind 2 Sanilac Co., MI 50 51 (f) Wind Intermittent 46 Beebe Gratiot Co., MI 34 51 (f) Wind Intermittent 42 Michigan Wind 1 Huron Co., MI 46 51 (f) Wind Intermittent 35 Harvest 2 Huron Co., MI 33 51 (f) Wind Intermittent 30 Harvest Huron Co., MI 31 51 (f) Wind Intermittent 26 Beebe 1B Gratiot Co., MI 21 51 (f) Wind Intermittent 26 CP Windfarm Faribault Co., MN 2 51 (f) Wind Intermittent 2 Clinton Battery Storage Blanchester, OH 1 Energy Storage Peaking 5 Total Midwest 11,605 Mid-Atlantic Limerick Sanatoga, PA 2 Uranium Base-load 2,315 Calvert Cliffs Lusby, MD 2 Uranium Base-load 1,789 Peach Bottom Delta, PA 2 50 Uranium Base-load 1,324 Salem Lower Alloways Creek Township, NJ 2 42.59 Uranium Base-load 995 Conowingo Darlington, MD 11 Hydroelectric Base-load 497 Criterion Oakland, MD 28 51 (f) Wind Intermittent 36 Fair Wind Garrett County, MD 12 Wind Intermittent 30 Fourmile Ridge Garrett County, MD 16 51 (f) Wind Intermittent 20 Solar Horizons Emmitsburg, MD 1 51 (f) Solar Intermittent 8 Solar New Jersey 3 Middle Township, NJ 5 51 (f) Solar Intermittent 1 Muddy Run Drumore, PA 8 Hydroelectric Intermediate 1,058 Eddystone 3, 4 Eddystone, PA 2 Oil/Gas Peaking 760 (i) Perryman Aberdeen, MD 5 Oil/Gas Peaking 404 Croydon West Bristol, PA 8 Oil Peaking 391 Handsome Lake Kennerdell, PA 5 Gas Peaking 268 Richmond Philadelphia, PA 2 Oil Peaking 98 Philadelphia Road Baltimore, MD 4 Oil Peaking 60 Eddystone Eddystone, PA 4 Oil Peaking 60 Delaware Philadelphia, PA 4 Oil Peaking 56 30 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Southwark Philadelphia, PA 4 Oil Peaking 52 Falls Morrisville, PA 3 Oil Peaking 51 Moser Lower Pottsgrove Twp., PA 3 Oil Peaking 51 Chester Chester, PA 3 Oil Peaking 39 Schuylkill Philadelphia, PA 2 Oil Peaking 30 Total Mid-Atlantic 10,393 ERCOT South Texas Project Bay City, TX 2 44 Uranium Base-load 1,161 Whitetail Webb County, TX 57 51 (f) Wind Intermittent 47 Sendero Jim Hogg and Zapata County, TX 39 51 (f) Wind Intermittent 40 Colorado Bend II Wharton, TX 3 Gas Intermediate 1,138 Wolf Hollow II Granbury, TX 3 Gas Intermediate 1,103 Handley 3 Fort Worth, TX 1 Gas Intermediate 375 Handley 4, 5 Fort Worth, TX 2 Gas Peaking 870 Total ERCOT 4,734 New York Nine Mile Point Scriba, NY 2 (g) Uranium Base-load 1,675 FitzPatrick Scriba, NY 1 Uranium Base-load 842 Ginna Ontario, NY 1 Uranium Base-load 576 Total New York 3,093 Other Antelope Valley Lancaster, CA 1 Solar Intermittent 242 Bluestem Beaver County, OK 60 51 (f)(h) Wind Intermittent 101 Shooting Star Kiowa County, KS 65 51 (f) Wind Intermittent 53 Bluegrass Ridge King City, MO 27 51 (f) Wind Intermittent 29 Conception Barnard, MO 24 51 (f) Wind Intermittent 26 Cow Branch Rock Port, MO 24 51 (f) Wind Intermittent 26 Mountain Home Glenns Ferry, ID 20 51 (f) Wind Intermittent 21 High Mesa Elmore Co., ID 19 51 (f) Wind Intermittent 20 Echo 1 Echo, OR 21 50.49 (f) Wind Intermittent 17 Sacramento PV Energy Sacramento, CA 4 51 (f) Solar Intermittent 15 Cassia Buhl, ID 13 51 (f) Wind Intermittent 14 Wildcat Lovington, NM 13 51 (f) Wind Intermittent 14 Echo 2 Echo, OR 9 51 (f) Wind Intermittent 9 Tuana Springs Hagerman, ID 8 51 (f) Wind Intermittent 9 Greensburg Greensburg, KS 10 51 (f) Wind Intermittent 6 Threemile Canyon Boardman, OR 6 51 (f) Wind Intermittent 5 Loess Hills Rock Port, MO 4 Wind Intermittent 5 Denver Airport Solar Denver, CO 1 51 (f) Solar Intermittent 2 31 Table of Contents Station (a) Location No. of Units Percent Owned (b) Primary Fuel Type Primary Dispatch Type (c) Net Generation Capacity (MWs) (d) Mystic 8, 9 Charlestown, MA 6 Gas Intermediate 1,413 (e) Hillabee Alexander City, AL 3 Gas Intermediate 753 Wyman 4 Yarmouth, ME 1 5.9 Oil Intermediate 36 West Medway II West Medway, MA 2 Oil/Gas Peaking 193 West Medway West Medway, MA 3 Oil Peaking 124 Grand Prairie Alberta, Canada 1 Gas Peaking 105 Framingham Framingham, MA 3 Oil Peaking 31 Total Other 3,269 Total 33,094 __________ (a) All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem, and STP units which are pressurized water reactors.
(b) 100%, unless otherwise indicated. (c) Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements.
(b) 100%, unless otherwise indicated. (c) Base-load units are those that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are those with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements.
Natural gas and oil stations and wind and solar facilities reflect a summer rating. (e) On August 9, 2020, we announced we would permanently cease generation operations at Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. On September 15, 2021, we reversed the previous decision to retire Byron and Dresden.
For nuclear stations, capacity reflects the annual mean rating. Natural gas and oil stations and wind and solar facilities reflect a summer rating. (e) On August 9, 2020, we announced we would permanently cease generation operations at Byron and Dresden nuclear stations in 2021 and Mystic Units 8 and 9 in 2024.
Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. (d) For nuclear stations, capacity reflects the annual mean rating.
Intermediate units are those that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. (d) Net generation capacity is stated at proportionate ownership share.
See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. (f) Net generation capacity is stated at proportionate ownership share. (g) Reflects the prior sale of 49% of CRP to a third party. See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information.
On September 15, 2021, we reversed the previous decision to retire Byron and Dresden. See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. (f) Reflects the prior sale of 49% of CRP to a third party.
(i) We wholly own Nine Mile Point Unit 1 and have an 82% undivided ownership interest in Nine Mile Point Unit 2. 45 Table of Contents (j) CRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets.
(h) CRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. (i) Eddystone stations 3 and 4 will be retiring in June 2025.
Removed
(h) We have deactivated the site and are evaluating for potential return of service or retirement beyond 2023.
Added
See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. (g) We wholly own Nine Mile Point Unit 1 and have an 82% undivided ownership interest in Nine Mile Point Unit 2.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeITEM 3. LEGAL PROCEEDINGS We are parties to various lawsuits and regulatory proceedings in the ordinary course of business. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references. ITEM 4.
Biggest changeITEM 3. LEGAL PROCEEDINGS We are parties to various lawsuits and regulatory proceedings in the ordinary course of business. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 19 — Commitments 32 Table of Contents and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeFourth Quarter Third Quarter Second Quarter First Quarter $ 0.1410 $ 0.1410 $ 0.1410 $ 0.1410 First Quarter 2023 Dividend On February 15, 2023, our Board of Directors declared a regular quarterly dividend of $0.2820 per share on our common stock for the first quarter of 2023.
Biggest changeThe following table sets forth Constellation’s quarterly cash dividends per share paid during 2023 and 2022. 2023 2022 Fourth Quarter Third Quarter Second Quarter First Quarter Fourth Quarter Third Quarter Second Quarter First Quarter $ 0.2820 $ 0.2820 $ 0.2820 $ 0.2820 $ 0.1410 $ 0.1410 $ 0.1410 $ 0.1410 First Quarter 2024 Dividend On February 26, 2024, our Board of Directors declared a regular quarterly dividend of $0.3525 per share on our common stock for the first quarter of 2024.
Stock Performance Graph The performance graph below illustrates a one-year comparison of cumulative total returns based on an initial investment of $100 in CEG Parent common stock, as compared with the S&P 500 Stock Index and the Philadelphia Utility Sector Index, or UTY, for the year 2022.
Stock Performance Graph The performance graph below illustrates a two-year comparison of cumulative total returns based on an initial investment of $100 in CEG Parent common stock, as compared with the S&P 500 Stock Index and the Philadelphia Utility Sector Index, or UTY, for the period 2022 through 2023.
This performance chart assumes: • $100 invested on February 1, 2022, in CEG Parent common stock, the S&P 500 Stock Index, and the UTY, and • All dividends are reinvested. 46 Table of Contents Value of Investment in 2022 2/1 12/31 CEG $100 $175 S&P 500 $100 $86 UTY $100 $107 Constellation As of January 31, 2023, CEG Parent directly held the entire membership interest in Constellation.
This performance chart assumes: • $100 invested on February 1, 2022, in CEG Parent common stock, the S&P 500 Stock Index, and the UTY, and • All dividends are reinvested. 46 Table of Contents Value of Investment 2/1/22 12/31/22 12/31/23 CEG $100 $175 $240 S&P 500 $100 $86 $108 UTY $100 $107 $96 Constellation As of January 31, 2024, CEG Parent directly held the entire membership interest in Constellation.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES CEG Parent Our common stock is listed on the Nasdaq (trading symbol: CEG). As of January 31, 2023 there were 327,131,082 shares of common stock outstanding and approximately 75,145 record holders of common stock.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES CEG Parent Our common stock is listed on the Nasdaq (trading symbol: CEG). As of January 31, 2024 there were 316,666,538 shares of common stock outstanding and approximately 70,439 record holders of common stock.
Constellation's revolving credit facility contains a covenant requiring it to maintain a consolidated leverage ratio calculated as the ratio of its consolidated indebtedness to its consolidated earnings before interest, taxes, depreciation and amortization.
Constellation's revolving credit facility contains a covenant requiring it to maintain a consolidated leverage ratio calculated as the ratio of its consolidated indebtedness to its consolidated earnings before interest, taxes, depreciation and amortization. Maintaining that ratio may affect Constellation's ability to make distributions to the CEG Parent. Our Board of Directors approved an updated dividend policy for 2024.
The dividend is payable on Friday, March 10, 2023, to shareholders of record as of 5 p.m. Eastern time on Monday, February 27, 2023. Unregistered Sales of Equity Securities None. Issuer Purchases of Equity Securities None.
The dividend is payable on Tuesday, March 19, 2024, to shareholders of record as of 5 p.m. Eastern time on Friday, March 8, 2024. Unregistered Sales of Equity Securities None. Issuer Purchases of Equity Securities Our Board of Directors considers share buybacks to be one of several ways we can provide value to our shareholders through our deployment of capital.
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Maintaining that ratio may affect Constellation's ability to make distributions to the CEG Parent. 47 Table of Contents Our Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.2820 per share. The following table sets forth Constellation’s quarterly cash dividends per share paid during 2022.
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The 2024 quarterly dividend will be $0.3525 per share.
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The first is to maintain strong investment grade metrics in addition to the pursuit of organic and inorganic growth consistent with our role as a leader in the clean energy transition.
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Our deployment of capital can also include the repurchase of shares if they can be acquired at attractive prices and increases to our dividend, which currently targets a 10% annual growth rate. We take into account the excise taxes imposed and other administrative costs when assessing our repurchase program.
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We believe that our share buyback policy is in the best interests of our company and its shareholders and is also consistent with the interests of our other stakeholders. 47 Table of Contents On February 16, 2023, as part of our capital allocation plan, our Board of Directors announced a share repurchase program with a $1 billion authority without expiration.
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Repurchases under this program commenced in March 2023. Shares repurchased were made through open market transactions and purchases pursuant to a Rule 10b5-1 trading plan. All repurchased shares were constructively retired and cancelled.
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On December 12, 2023, our Board of Directors approved an increase to our previously announced $1 billion share repurchase program, authorizing the repurchase of up to an additional $1 billion of the Company’s outstanding common stock.
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On November 9, 2023, we entered into a stock purchase plan for the purchase of shares of our common stock (November 2023 Stock Purchase Plan), designed to comply with Rule 10b5-1 under the Exchange Act.
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Under its terms, the November 2023 Stock Purchase Plan would expire at the later of the completion of the maximum purchase amount of $250 million of shares of our common stock, or December 31, 2023.
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During 2023, we repurchased from the open market approximately 10.6 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $1 billion. As of December 31, 2023, there was $1 billion of remaining authority to repurchase shares.
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The following table provides information regarding our share repurchases under the program during the three months ended December 31, 2023.
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All repurchases disclosed were made pursuant to the November 2023 Stock Purchase Plan: Period Total Number of Shares Purchased (a) Average Price Paid per Share (b) Approximate Dollar Value of Shares that May Yet Be Purchased Under the Programs (c) October 1, 2023 to October 31, 2023 — $ — $ 244,000,000 November 1, 2023 to November 30, 2023 993,800 $ 122.84 $ 121,000,000 December 1, 2023 to December 31, 2023 (d) 1,031,569 $ 115.75 $ 1,000,000,000 Total 2,025,369 $ 119.22 $ 1,000,000,000 __________ (a) We have not made any purchases of shares other than in connection with the publicly announced share repurchase program described above.
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(b) Average price paid per share for open market transactions excludes taxes and commissions. (c) Approximate dollar value of shares that may yet be purchased under the program includes taxes and commissions. (d) Includes increase of additional $1 billion of share repurchase authority. ITEM 6. RESERVED Not Applicable.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

131 edited+44 added−33 removed107 unchanged
Biggest changeFor the year ended December 31, 2022 compared to 2021, Purchased power and fuel expense by region were as follows: 2022 vs. 2021 2022 2021 Variance % Change (a) Mid-Atlantic $ 3,026 $ 2,320 $ (706) (30.4) % Midwest 1,886 1,343 (543) (40.4) % New York 528 414 (114) (27.5) % ERCOT 1,136 2,006 870 43.4 % Other Power Regions 5,811 3,999 (1,812) (45.3) % Total electric purchased power and fuel 12,387 10,082 (2,305) (22.9) % Other 5,250 3,279 (1,971) (60.1) % Mark-to-market gains (175) (1,198) (1,023) Total purchased power and fuel $ 17,462 $ 12,163 $ (5,299) (43.6) % __________ (a) % Change in mark-to-market is not a meaningful measure. 65 Table of Contents For the year ended December 31, 2022 compared to 2021, changes in Purchased power and fuel expense by region were approximately as follows: 2022 vs. 2021 Variance % Change (a) Description Mid-Atlantic $ (706) (30.4) % • unfavorable purchased power and net capacity impact of ($660) primarily due to higher energy prices, higher load, and lower capacity prices earned • unfavorable PJM net non-performance charges of ($7) due to generation performance against capacity requirements during December 2022 weather event Midwest (543) (40.4) % • unfavorable purchased power and net capacity impact of ($590) primarily due to higher energy prices, lower capacity prices earned, and lower cleared capacity volumes; partially offset by • favorable nuclear fuel cost of $65 primarily due to the absence of accelerated amortization of nuclear fuel and lower nuclear fuel prices in the prior year New York (114) (27.5) % • unfavorable purchased power and net capacity impact of ($190) primarily due to higher energy prices, lower nuclear generation and lower capacity prices earned; partially offset by • favorable settlement of economic hedges of $90 due to settled prices relative to hedged prices ERCOT 870 43.4 % • favorable purchased power of $635 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 $140 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 (1,812) (45.3) % • unfavorable purchased power and net capacity impact of ($2,180) primarily due to higher energy prices, higher load, lower cleared capacity volumes and lower capacity prices earned • unfavorable fuel cost of ($400) primarily due to higher gas prices • unfavorable environmental products activity of ($415) primarily driven by lower optimization and higher RPS costs; partially offset by • favorable settlement of economic hedges of $1,210 due to settled prices relative to hedged prices Other (1,971) (60.1) % • unfavorable net gas purchase costs and settlement of economic hedges of ($1,885) • unfavorable energy purchases of ($290) primarily due to higher energy prices • unfavorable fair value adjustment related to gas imbalances of ($50); partially offset by • favorable impact due to the absence of LDC and pipeline penalties due to the February 2021 extreme cold weather event of $110 • favorable impact due to the absence of accelerated nuclear fuel amortization associated with announced early plant retirements of $150 66 Table of Contents Mark-to-market (b) (1,023) • gains on economic hedging activities of $175 in 2022 compared to gains of $1,198 in 2021 Total $ (5,299) (43.6) % __________ (a) % Change in mark-to-market is not a meaningful measure.
Biggest changeFor the year ended December 31, 2023 compared to 2022, changes in Purchased power and fuel expense by region were approximately as follows: 2023 vs. 2022 Variance % Change (a) Description Mid-Atlantic $ 812 26.8 % • favorable purchased power and net capacity impact of $960 primarily due to lower energy and capacity prices; partially offset by • unfavorable environmental products activity of ($160) primarily due to higher load served and REC prices Midwest 483 25.6 % • favorable cost associated with power delivery and net capacity impact of $525 primarily due to lower energy and capacity prices earned New York (242) (45.8) % • 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 $130 primarily due to lower energy prices and partially offset by higher capacity prices ERCOT 372 32.7 % • favorable settlement of economic hedges of $245 due to settled prices relative to hedged prices • favorable fuel cost of $70 primarily due to lower gas prices partially offset by higher generation • favorable purchased power of $65 primarily due to lower energy prices and higher generation partially offset by higher load served Other Power Regions 1,200 20.7 % • favorable purchased power and fuel of $3,235 primarily due to lower energy prices and lower load served; partially offset by • unfavorable settlement of economic hedges of ($1,965) due to settled prices relative to hedged prices • unfavorable environmental products activity of ($55) primarily driven higher REC prices 65 Table of Contents 2023 vs. 2022 Variance % Change (a) Description Other 1,382 26.3 % • favorable net gas purchase costs and settlement of economic hedges of $1,160 primarily due to lower gas prices • favorable purchases in the United Kingdom of $180 primarily due to lower energy prices • favorable fair value adjustment related to gas imbalances of $45 Mark-to-market (b) (2,546) • losses on economic hedging activities of ($2,371) in 2023 compared to gains of $175 in 2022 Total $ 1,461 8.4 % __________ (a) % Change in mark-to-market is not a meaningful measure.
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.
Significant Transactions and Developments Separation from Exelon On February 21, 2021, Exelon’s Board of Directors approved a plan to separate its competitive generation and customer-facing energy businesses into a stand-alone publicly traded company (the "separation"). Exelon completed the separation on February 1, 2022.
The assumptions are updated annually and upon any interim remeasurement of the plan obligations. 55 Table of Contents 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, private credit, and hedge funds. Expected Rate of Return on Plan Assets.
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, private credit, and hedge funds. 55 Table of Contents Expected Rate of Return on Plan Assets.
We are taking this affirmative action by working with our diverse set of suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term and provide the necessary fuel to bridge potential Russian supply disruption through 2028, which is the date multiple suppliers are expected to have incremental capacity online.
We are 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.
See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivables. • 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.
See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer 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.
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 Loss Attributable to Common Shareholders included in the table below, may provide a more complete understanding of factors and trends affecting our business.
Adjusted EBITDA (non-GAAP) 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 business.
See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending. • Collection of DPP, net increased due to cash collections from the accounts receivable Facility, as discussed in the Cash Flows from Operating Activities section above.
See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending. • Collection of DPP, net increased due to cash collections from the customer accounts receivable Facility, as discussed in the Cash Flows from Operating Activities section above.
(e) Represents the future estimated value at December 31, 2022 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into with third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
(e) Represents the future estimated value at December 31, 2023 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into with third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
Planned additions and upgrades and other investments are subject to periodic review and revision to reflect changes in economic conditions impacting our generating assets and other factors, including, but not limited to, market power prices, results of capacity auctions, potential legislative and regulatory solutions, impacts of inflation, changes in the cost of materials and labor, and financing costs.
Planned additions and upgrades and other investments are subject to periodic review and revision to reflect changes in economic conditions impacting our generating assets and other factors, including, but not limited to, market power prices, results of capacity auctions, potential legislative and regulatory actions, impacts of inflation, changes in the cost of materials and labor, and financing costs.
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. At separation and upon remeasurement as of December 31, 2022, we utilized the mortality tables and projection scales released by the SOA.
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. At separation and upon remeasurement as of December 31, 2023, we utilized the mortality tables and projection scales released by the SOA.
(f) These amounts represent our expected contributions to our qualified pension plans. Qualified pension contributions for years after 2028 are not included. See Note 19 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of our other commitments potentially triggered by future events.
(f) These amounts represent our expected contributions to our qualified pension plans. Qualified pension contributions for years after 2029 are not included. See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of our other commitments potentially triggered by future events.
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).
The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of RTO/ISO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail).
As of December 31, 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.
As of December 31, 2023, 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.
The determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3), such as revenue and generation forecasts, projected capital, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources.
The determination of fair value is driven by both internal assumptions that include significant unobservable inputs, such as revenue and generation forecasts, projected capital, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources.
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).
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).
We anticipate funding these capital expenditures with a combination of internally generated funds and borrowings . 74 Table of Contents Pension and Other Postretirement Benefits We consider various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation.
We anticipate funding these capital expenditures with a combination of internally generated funds and borrowings. Pension and Other Postretirement Benefits We consider various factors when making pension funding decisions, including actuarially-determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation.
This was partially offset by a reduction in cash proceeds received from the Purchasers in 2022 compared to 2021. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
This was partially offset by a reduction in cash proceeds received from the Purchasers in 2023 compared to 2022. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal. 51 Table of Contents The actual decommissioning approach selected will be determined at the time of shutdown and may be influenced by multiple factors including the funding status of the NDT funds at the time of shutdown and regulatory or other commitments.
In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal. The actual decommissioning approach selected will be determined at the time of shutdown and may be influenced by multiple factors including the funding status of the NDT funds at the time of shutdown and regulatory or other commitments.
See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral. • Option premiums paid, net relate to options contracts that we purchase and sell as part of our established policies and procedures to manage risks associated with market fluctuations in commodity prices.
See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral. • Option premiums paid, net relate to options contracts that we purchase and sell as part of our established policies and procedures to manage risks associated with market fluctuations in commodity 69 Table of Contents prices.
Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope of new authoritative guidance. All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS.
Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope of new authoritative guidance. 54 Table of Contents All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions, unless otherwise noted) Executive Overview We are a supplier of clean energy. Our generating capacity primarily consists of nuclear, wind, solar, natural gas and hydroelectric assets.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions, unless otherwise noted) Executive Overview We are a supplier of carbon-free energy. Our generating capacity primarily consists of nuclear, wind, solar, natural gas and hydroelectric assets.
We report capacity on a net monthly basis within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. The following table presents the average capacity prices ($/MW Day) for each of our major regions.
Capacity prices have a significant impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. The following table presents the average capacity prices ($/MW Day) for each of our major regions.
Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR rates used in creating the initial ARO cost layers.
Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR rates used in creating the initial ARO cost 51 Table of Contents layers.
Transactions within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS and spot-market energy commodity sales, including settlements with ISOs. The determination of our retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly.
Transactions within the scope of 57 Table of Contents Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS and spot-market energy commodity sales, including settlements with RTOs and ISOs. The determination of our retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly.
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.
Our business is capital intensive and requires considerable capital resources. We 67 Table of Contents 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.
We consider nonperformance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in our assessment of nonperformance risk. The impacts of nonperformance and credit risk to date have generally not been material to the consolidated financial statements. See ITEM 7A.
We consider non-performance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in our assessment of non-performance risk. The impacts of non-performance and credit risk to date have generally not been material to the consolidated financial statements. See ITEM 7A.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2021 Form 10-K, which was filed with the SEC on February 25, 2022. Capital Allocation and Growth Announcements We are announcing our capital allocation strategy for 2023 and 2024 supporting our core principles outlined in our Strategy and Outlook discussion. See ITEM 1.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2022 Form 10-K, which was filed with the SEC on February 16, 2023. Capital Allocation and Growth Announcements We are announcing our capital allocation strategy for 2024 and 2025 supporting our core principles outlined in our Strategy and Outlook discussion. See ITEM 1.
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. 58 Table of Contents The following table provides a reconciliation between Net loss attributable to common shareholders as determined in accordance with GAAP and Adjusted EBITDA (non-GAAP) for the twelve months ended December 31, 2022 compared to the same period in 2021.
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. 58 Table of Contents 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 year ended December 31, 2023 compared to the same period in 2022.
The cash flows from our generating units are generally evaluated at a regional portfolio level (asset group) given the interdependency of cash flows generated from the customer supply and risk management activities within each region.
The cash flows from our generating units are generally evaluated at a regional portfolio level (asset group) given the interdependency of cash flows generated from the customer supply and 53 Table of Contents risk management activities within each region.
Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information.
Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the 56 Table of Contents position will be examined by a taxing authority having full knowledge of all relevant information.
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.
Borrowings under these agreements are secured by the 75 Table of Contents assets and equity of each respective project. Lenders do not have recourse against us in the event of a default.
Liquidity and Capital Resources For discussion of the year ended December 31, 2021 compared to the year ended December 31, 2020, refer to Liquidity and Capital Resources of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2021 Form 10-K which was filed with the SEC on February 25, 2022.
Liquidity and Capital Resources For discussion of the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to Liquidity and Capital Resources of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2022 Form 10-K which was filed with the SEC on February 16, 2023.
The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant: Change in ARO Assumption Increase (Decrease) to ARO as of December 31, 2022 Cost escalation studies Uniform increase in escalation rates of 50 basis points $ 1,780 Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 10 percent 720 Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent (a) 140 Shorten each unit's probability weighted operating life assumption by 10 percent (b) 280 Extend the estimated date for DOE acceptance of SNF to 2040 (70) __________ (a) Excludes any sites in which management has committed to a specific decommissioning approach.
The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant: Change in ARO Assumption Increase (Decrease) to ARO as of December 31, 2023 Cost escalation studies Uniform increase in escalation rates of 50 basis points $ 1,860 Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 10 percent 770 Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent (a) 140 Shorten each unit's probability-weighted operating life assumption by 10 percent (b) 220 Extend the estimated date for DOE acceptance of SNF to 2040 (80) __________ (a) Excludes any sites in which management has committed to a specific decommissioning approach.
See Note 1 - Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information. Effective income tax rates were 71.6% and 148% for the years ended December 31, 2022 and 2021, respectively.
See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information. Effective income tax rates were 35.1% and 71.6% for the years ended December 31, 2023 and 2022, respectively.
Approximately 45-47% of projected capital expenditures are for the acquisition of nuclear fuel, which includes additional nuclear fuel to increase inventory levels. This is a strategic decision in response to the potential for the continuing Russia and Ukraine conflict to impact our long-term nuclear fuel supply. See ITEM 7.
Approximately 44% - 47% of projected capital expenditures are for the acquisition of nuclear fuel, which includes additional nuclear fuel to increase inventory levels. This is a strategic decision in response to the potential for the continuing Russia and Ukraine conflict to impact our long-term nuclear fuel supply.
In certain cases, our generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third-party and operations are independent of other generating assets (typically contracted renewables). 53 Table of Contents On a quarterly basis, we assess our long-lived assets or asset groups for indicators of potential impairment.
In certain cases, our generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third-party and operations are independent of other generating assets (typically contracted renewable generation). On a quarterly basis, we assess our long-lived assets or asset groups for indicators of potential impairment.
If we had lost our investment grade credit rating as of December 31, 2022, we would have been required to provide incremental collateral estimated to be approximately $3.3 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.
If we had lost our investment grade credit ratings as of December 31, 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.
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.
No later than two years after shutting down a plant, we must submit a Post-shutdown Decommissioning Activities Report (PSDAR) to the NRC that includes the planned option for decommissioning the site.
(e) The nonrecourse debt has an average blended interest rate. From time to time and as market conditions warrant, we may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt.
(c) The nonrecourse debt has an average blended interest rate. 72 Table of Contents From time to time and as market conditions warrant, we may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt.
(c) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. 72 Table of Contents During 2022, the following long-term debt was retired and/or redeemed: Type Interest Rate Maturity Amount Senior Notes 3.40% March 15, 2022 $ 500 Senior Notes 4.25% June 15, 2022 523 CR Nonrecourse Debt (a) 3 month LIBOR + 2.50% December 15, 2027 41 Continental Wind Nonrecourse Debt (a) 6.00% February 28, 2033 37 West Medway II Nonrecourse Debt (a) 1 month LIBOR + 2.875% (c) March 31, 2026 24 Antelope Valley DOE Nonrecourse Debt (a)(b) 2.29% - 3.56% January 5, 2037 25 RPG Nonrecourse Debt (a) 4.11% March 31, 2035 9 Energy Efficiency Project Financing 3.71% December 31, 2022 3 __________ (a) See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.
During 2022, the following long-term debt was retired and/or redeemed: Type Interest Rate Maturity Amount Senior Notes 3.40% March 15, 2022 $ 500 Senior Notes 4.25% June 15, 2022 523 CR Nonrecourse Debt (a) 3-month LIBOR + 2.50% December 15, 2027 41 Continental Wind Nonrecourse Debt (a) 6.00% February 28, 2033 37 West Medway II Nonrecourse Debt (a) 1 month LIBOR + 2.875% (c) March 31, 2026 24 Antelope Valley DOE Nonrecourse Debt (a)(b) 2.29% - 3.56% January 5, 2037 25 RPG Nonrecourse Debt (a) 4.11% March 31, 2035 9 Energy Efficiency Project Financing 3.71% December 31, 2022 3 Total $ 1,162 __________ (a) See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.
As of December 31, 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 2022 to fund our short-term liquidity needs, when necessary.
As of December 31, 2023, we have access to facilities with aggregate bank commitments of $6.1 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during 2023 to fund our short-term liquidity needs, when necessary.
Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions 68 Table of Contents 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 $5.8 billion.
Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $6.1 billion.
Prior to our separation from Exelon, we were self-insured for general liability, automotive liability, and workers’ compensation claims. Upon separation, we now maintain insurance coverage for general liability, automotive liability, and workers’ compensation and are self-insured to the extent that losses are within policy deductibles or exceed the amount of insurance maintained.
Prior to our separation from Exelon, we were self-insured for general liability, automotive liability, and workers’ compensation claims. For accidents occurring post-separation, we maintain insurance coverage for general liability, automotive liability, workers’ compensation, and personal injury claims and are self-insured to the extent that losses are within policy deductibles or exceed the amount of insurance maintained.
The following table sets forth our GAAP consolidated Net Loss Attributable to Common Shareholders for the twelve months ended December 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the twelve months ended December 31, 2022 and 2021 see the discussions of Results of Operations below.
The following table sets forth our GAAP consolidated Net Income (Loss) Attributable to Common Shareholders for the year ended December 31, 2023 compared to the same period in 2022. For additional information regarding the financial results for the years ended December 31, 2023 and 2022 see the discussions of Results of Operations below.
Nuclear Decommissioning Asset Retirement Obligations The AROs associated with decommissioning our nuclear un its were $12.5 billion at December 31, 2022. The authoritative guidance requires that we estimate our obligation for the future decommissioning of our nuclear generating plants.
Nuclear Decommissioning Asset Retirement Obligations The AROs associated with decommissioning our nuclear un its were $13.9 billion at December 31, 2023. The authoritative guidance requires that we estimate our obligation for the future decommissioning of our nuclear generating plants.
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2022 compared to the year ended December 31, 2021. For discussion of the year ended December 31, 2021 compared to the year ended December 31, 2020, refer to ITEM 7.
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2023 compared to the year ended December 31, 2022. For discussion of the year ended December 31, 2022 48 Table of Contents compared to the year ended December 31, 2021, refer to ITEM 7.
(b) On January 6, 2023, we redeemed $5 million of 2.29% - 3.56% Antelope Valley DOE nonrecourse debt. (c) The nonrecourse debt has an average blended interest rate.
(c) On January 5, 2024, we redeemed $5.5 million of 2.29% - 3.56% Antelope Valley DOE nonrecourse debt. (d) The nonrecourse debt has an average blended interest rate.
The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO: Change in the CARFR applied to the annual ARO update Increase (Decrease) to ARO as of December 31, 2022 2021 CARFR rather than the 2022 CARFR $ 3,470 2022 CARFR increased by 50 basis points (570) 2022 CARFR decreased by 50 basis points 710 52 Table of Contents ARO Sensitivities.
The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO: Change in the CARFR applied to the annual ARO update Increase (Decrease) to ARO as of December 31, 2023 2022 CARFR rather than the 2023 CARFR $ 520 2023 CARFR increased by 50 basis points (290) 2023 CARFR decreased by 50 basis points 350 ARO Sensitivities.
Dividends Quarterly dividends declared by our Board of Directors during the twelve months ended December 31, 2022 and for the first quarter of 2023 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 First Quarter of 2023 February 15, 2023 February 27, 2023 March 10, 2023 $ 0.2820 73 Table of Contents 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.
Dividends Quarterly dividends declared by our Board of Directors during 2023 and for the first quarter of 2024 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 $ 0.2820 Second Quarter of 2023 April 25, 2023 May 12, 2023 June 9, 2023 $ 0.2820 Third Quarter of 2023 August 1, 2023 August 14, 2023 September 8, 2023 $ 0.2820 Fourth Quarter of 2023 November 1, 2023 November 17, 2023 December 8, 2023 $ 0.2820 First Quarter of 2024 February 26, 2024 March 8, 2024 March 19, 2024 $ 0.3525 Credit Matters and Cash Requirements We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities.
See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation. 71 Table of Contents • Contributions from Exelon is primarily related to a cash contribution of $1.75 billion from Exelon on January 31, 2022, pursuant to the Separation Agreement.
See Note 20 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. • Contributions from Exelon is primarily related to a cash contribution of $1.75 billion from Exelon on January 31, 2022, pursuant to the Separation Agreement.
The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2023 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Planned contributions $ 21 $ 10 $ 17 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.
The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2024 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Total Planned contributions $ 161 $ 13 $ 20 $ 194 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.
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. 2022 2021 Nuclear fleet capacity factor 94.8 % 94.5 % Refueling outage days 212 262 Non-refueling outage days 54 34 62 Table of Contents ZEC Prices.
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. 2023 2022 Nuclear fleet capacity factor 94.4 % 94.8 % Refueling outage days 256 212 Non-refueling outage days 51 54 ZEC Prices.
See below for quarterly dividends declared. • Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for additional information. • Changes in short-term borrowings, net , is driven by repayments on and issuances of notes due in less than 365 days.
Refer to debt issuances and redemptions tables 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.
Effective February 1, 2022, the non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information. (d) For 2022, includes net realized and unrealized (losses) gains from equity investments.
Effective February 1, 2022, the non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
If all our future nominal cash flows associated with the ARO were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $12.5 billion to approximately $10.5 billion.
If all our future nominal cash flows associated with the ARO were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $13.9 billion to approximately $11.3 billion.
Refer to Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings. Debt Issuances and Redemptions See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our long-term debt.
See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information on the separation. Debt Issuances and Redemptions See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our long-term debt.
See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information. We incurred separation costs of $140 million and $49 million for the twelve months ended December 31, 2022 and 2021, respectively, which are primarily recorded in Operating and maintenance expense. We expect to incur incremental costs of approximately $80 million in 2023.
See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information. We incurred separation costs of $101 million and $140 million for the years ended December 31, 2023 and 2022, respectively, which are primarily recorded in Operating and maintenance expense.
See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.
See Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and non-pension postretirement benefit plans.
For 2021, includes net unrealized (losses) gains from equity investments. (e) Reflects amounts contractually owed to Exelon under the TMA, which is offset in Income taxes. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. (f) Amounts we billed Exelon for services pursuant to the TSA.
(d) This reflects amounts contractually owed to Exelon under the TMA, which is offset in Income taxes. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. (e) Includes amounts we billed Exelon for services pursuant to the TSA.
See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
See Note 1 — Basis of Presentation, Note 2 — Mergers, Acquisitions, and Dispositions, and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
The following table illustrates the effects of changing certain of the actuarial assumptions reflected above and as discussed in Note 15 — 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 2023 cost: Discount rate (a) 5.52 % 5.50 % 0.5 % $ (13) $ (1) $ (14) 5.52 % 5.50 % (0.5) % 16 2 18 EROA 6.50 % 6.50 % 0.5 % (40) (4) (44) 6.50 % 6.50 % (0.5) % 40 4 44 Change in benefit obligation: Discount rate (a) 5.52 % 5.50 % 0.5 % (345) (61) (406) 5.52 % 5.50 % (0.5) % 391 69 460 __________ (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%.
The following table illustrates the effects of changing certain of the actuarial assumptions reflected above and as discussed in Note 15 — 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 2024 cost: Discount rate (a) 5.52 % 5.50 % 0.5 % $ (14) $ — $ (14) 5.52 % 5.50 % (0.5) % 14 1 15 EROA 6.50 % 6.51 % 0.5 % (39) (4) (43) 6.50 % 6.51 % (0.5) % 39 4 43 Change in benefit obligation: Discount rate (a) 5.17 % 5.15 % 0.5 % (349) (64) (413) 5.17 % 5.15 % (0.5) % 380 69 449 __________ (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%.
Twelve Months Ended December 31, Favorable Variance 2022 2021 GAAP Net Loss Attributable to Common Shareholders $ (160) $ (205) $ 45 Adjusted EBITDA (non-GAAP). In analyzing and planning for our business, we supplement our use of GAAP Net Loss Attributable to Common Shareholders with Adjusted EBITDA (non-GAAP) as a performance measure.
For the Years Ended December 31, Favorable Variance 2023 2022 GAAP Net Income (Loss) Attributable to Common Shareholders $ 1,623 $ (160) $ 1,783 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.
See Note 16 — Derivative Financial Instruments and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Capital Expenditures Our most recent estimate of capital expenditures is approximately $2.6 billion for 2023 and approximately $5.0 billion for the period from 2024 to 2025.
See Note 16 — Derivative Financial Instruments and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 73 Table of Contents Capital Expenditures Our most recent estimate of capital expenditures is approximately $2.8 billion and $2.3 billion for 2024 and 2025 respectively.
On October 16, 2019, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. On June 8, 2022, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for site restoration costs.
On October 16, 2019, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. On June 8, 2022, the NRC granted our exemption request to use the TMI Unit 1 NDT funds for site restoration costs. On November 16, 2023, Zion Station was transferred back to us from ZionSolutions.
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 December 31, 2022, we had $2.2 billion of available capacity and $0.4 billion of cash on hand.
A loss of investment grade credit rating would have required a three notch downgrade by S&P or a two notch downgrade by Moody's from their current levels of BBB+ and Baa2, to BB+ and Ba1 or below. respectively. As of December 31, 2023, we had $3.1 billion of available capacity and $0.4 billion of cash on hand.
Impairment of Long-Lived Assets We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable.
See Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. Impairment of Long-Lived Assets We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable.
We are also continuing to work with federal policymakers and other stakeholders to facilitate the expansion of the domestic nuclear fuel cycle within the United States to improve carbon-free energy security. Hedging Strategy We are exposed to commodity price risk associated with the unhedged portion of our electricity portfolio.
We 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.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information. 50 Table of Contents Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the consolidated financial statements.
Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the consolidated financial statements.
The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO due to upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO.
Increases in the ARO due to upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO.
Debt activity for 2022 and 2021 was as follows: During 2022, the following long-term debt was issued: Type Interest Rate Maturity Amount Use of Proceeds Energy Efficiency Project Financing (a) 2.20% - 6.96% March 31, 2023 - May 1, 2024 $ 14 Funding to install energy conservation measures. __________ (a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
(b) The Tax-Exempt Notes have a maturity date of March 1, 2025 - April 1, 2053, and a mandatory purchase date that ranges from March 1, 2025 - June 1, 2029. 71 Table of Contents During 2022, the following long-term debt was issued: Type Interest Rate Maturity Amount Use of Proceeds Energy Efficiency Project Financing (a) 2.20% - 6.96% March 31, 2023 - May 1, 2024 $ 14 Funding to install energy conservation measures __________ (a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
Energy delivered to customers that has not yet been billed as of the reporting period is estimated and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is based upon individual customer meter readings, forecasted volumes, and applicable rates. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information. Derivative Revenues.
Energy delivered to customers that has not yet been billed as of the reporting period is estimated and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is based upon individual customer meter readings, forecasted volumes, and applicable rates.
The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an initial 20-year license renewal term, (3) the probability of a second, 20-year license renewal term, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments.
The plant shutdown timing scenarios consider four alternatives: (1) the probability of early plant retirement, (2) the probability of operating through the original 40-year nuclear license term, (3) the probability of operating through an initial 20-year license renewal term, and (4) the probability of a second, 20-year license renewal term.
Other Key Business Drivers 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.
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, and pending legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit energy deliveries.
(b) Excludes any retired sites. See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs. Unamortized Energy Contract Assets and Liabilities Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that we have acquired.
(b) Excludes any retired sites. See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 18 — Fair Value of Financial Assets and Liabilities and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative instruments. Defined Benefit Pension and Other Postretirement Employee Benefits We sponsor defined benefit pension and OPEB plans for most current employees.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 16 — Derivative Financial Instruments and Note 18 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative instruments.
(f) 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 Transition Services Agreement (TSA).
(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.
Twelve Months Ended December 31, 2022 2021 Net Loss Attributable to Common Shareholders $ (160) $ (205) Income Taxes (a) (339) 225 Depreciation and Amortization (b) 1,091 3,003 Interest Expense, Net 251 297 Unrealized Loss (Gain) on Fair Value Adjustments (c) 1,058 (420) Asset Impairments (d) — 541 Plant Retirements and Divestitures (11) (4) Decommissioning-Related Activities (e) 820 (1,289) Pension & OPEB Non-Service Credits (116) (50) Separation Costs (f) 140 49 COVID-19 Direct Costs (g) — 35 Acquisition-Related Costs (h) — 21 ERP System Implementation Costs (i) 22 14 Change in Environmental Liabilities 10 12 Cost Management Program — 9 Prior Merger Commitment (j) (50) — Noncontrolling Interests (k) (49) (53) Adjusted EBITDA (non-GAAP) $ 2,667 $ 2,185 __________ (a) In 2022, includes amounts contractually owed to Exelon under the Tax Matters Agreement (TMA) reflected in Other, net.
For the Years Ended December 31, 2023 2022 Net Income (Loss) Attributable to Common Shareholders $ 1,623 $ (160) Income Tax (Benefit) Expense (a) 840 (339) Depreciation and Amortization 1,096 1,091 Interest Expense, Net 431 251 Unrealized (Gain) Loss on Fair Value Adjustments (b) 658 1,058 Asset Impairments 71 — Plant Retirements and Divestitures (28) (11) Decommissioning-Related Activities (c) (716) 820 Pension & OPEB Non-Service Credits (54) (116) Separation Costs (d) 101 140 Acquisition-Related Costs 12 — ERP System Implementation Costs (e) 25 22 Change in Environmental Liabilities 43 10 Prior Merger Commitment (f) — (50) Noncontrolling Interests (g) (77) (49) Adjusted EBITDA (non-GAAP) $ 4,025 $ 2,667 __________ (a) Includes amounts contractually owed to Exelon under the TMA reflected in Other, net.
BUSINESS – Constellation's Strategy and Outlook for additional information about our strategy. We will double the annual dividend in 2023 from $0.5640 per share to $1.1280 per share while targeting growth of 10% annually.
BUSINESS – Constellation's Strategy and Outlook for additional information about our strategy. We will increase the quarterly dividend by 25% to $0.3525 per share starting in 2024, while targeting growth of 10% annually.
The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions: Decommissioning Cost Studies.
These factors could result in material changes to our current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios. 50 Table of Contents The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions: Decommissioning Cost Studies.
Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements.
Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements. Commodity Contracts. Identification of a commodity contract as an economic hedge requires us to determine that the contract is in accordance with the RMP.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeMark-to-Market Energy Contract Net Assets Balance as of December 31, 2020 $ 729 (a) Total change in fair value during 2021 of contracts recorded in result of operations 797 Reclassification to realized at settlement of contracts recorded in results of operations (228) Changes in allocated collateral 96 Net option premium paid 338 Option premium amortization (125) Upfront payments and amortizations (b) 15 Balance as of December 31, 2021 $ 1,622 (a) Total change in fair value during 2022 of contracts recorded in result of operations (647) Reclassification to realized at settlement of contracts recorded in results of operations (380) Changes in allocated collateral 386 Net option premium paid 177 Option premium amortization (293) Upfront payments and amortizations (b) 167 Foreign Currency Translation 14 Balance as of December 31, 2022 $ 1,046 (a) __________ (a) Amounts are shown net of collateral paid to and received from counterparties.
Biggest changeSee Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2023 and 2022. 2023 2022 Beginning balance as of January 1 (a) $ 1,046 $ 1,622 Total change in fair value of contracts recorded in result of operations (2,530) (647) Reclassification to realized at settlement of contracts recorded in results of operations 1,561 (380) Changes in allocated collateral 1,502 386 Net option premium paid (received) (26) 177 Option premium amortization (183) (293) Upfront payments and amortizations (b) (249) 167 Foreign currency translation (13) 14 Ending balance as of December 31 (a) $ 1,108 $ 1,046 __________ (a) Amounts are shown net of collateral paid to and received from counterparties.
Electricity available from our owned or contracted generation supply in excess of our obligations to customers is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, we enter into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures.
Electricity available from our owned or contracted generation supply in excess of our obligations to customers is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, we enter non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures.
In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements.
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.
To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, we utilize foreign currency derivatives, which are typically designated as economic hedges. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, we utilize foreign currency derivatives, which are typically designated as economic hedges. See 79 Table of Contents Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk 76 Table of Contents exposures.
Liquidity and Capital Resources — Credit Matters and Cash Requirements — Credit Facilities for additional information. RTOs and ISOs We participate in all, or some, of the established, wholesale spot energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, OIESO, and ERCOT.
Liquidity and Capital Resources — Credit Matters and Cash Requirements — Credit Facilities for additional information. RTOs and ISOs We participate in all of the established wholesale spot energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, and ERCOT.
A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would not result in a material decrease in our pre-tax income for the year ended December 31, 2022.
A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would not have resulted in a material decrease in our pre-tax income for the year ended December 31, 2023.
We use derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. We expect the settlement of the majority of our economic hedges will occur during 2023 through 2025. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on our owned and contracted generation positions which have not been hedged.
We use derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. We expect the settlement of the majority of our economic hedges will occur during 2024 through 2026. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged.
The credit policies of the RTOs and ISOs may, under certain circumstances, 81 Table of Contents require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on our consolidated financial statements.
The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major member of an RTO/ISO could result in a material adverse impact on our consolidated financial statements.
Geopolitical developments, including the Russia and Ukraine conflict and United States sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium industry. Non-performance by these counterparties could have a material adverse impact in our consolidated financial statements.
Geopolitical developments, including the Russia and Ukraine conflict and United States, United Kingdom, European Union, and Canadian sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements.
We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy. A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would result in a $759 million reduction in the fair value of the trust assets as of December 31, 2022.
We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy. A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would have resulted in a $885 million reduction in the fair value of our NDT trust assets as of December 31, 2023.
(b) Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations. 79 Table of Contents Fair Values The following table presents maturity and source of fair value for mark-to-market commodity contract net assets (liabilities). The table provides two fundamental pieces of information.
(b) Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums and the associated amortizations. Fair Values The following table presents maturity and source of fair value for mark-to-market commodity contract net assets (liabilities).
(b) Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $898 million at December 31, 2022. Credit Risk We would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments.
(b) Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $2,400 million at December 31, 2023. 78 Table of Contents Credit Risk We would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments.
Approximately 60% of our uranium concentrate requirements from 2023 through 2027 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russian and Ukraine conflict.
Approximately 55% of our uranium concentrate requirements from 2024 through 2028 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russia and Ukraine conflict.
This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information. 82 Table of Contents
This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
The forecasted market price risk exposure for our entire economic hedge portfolio associated with a $5/MWh reduction in the annual average around-the-clock energy price based on December 31, 2022 market conditions and hedged position would be a decrease in pre-tax net income of approximately $8 million and $215 million for 2023 and 2024, respectively.
The forecasted market price risk exposure for our entire economic hedge portfolio associated with a $5/MWh reduction in the annual average around-the-clock energy price based on December 31, 2023 market conditions and hedged position results in an immaterial impact to net income (loss) for 2024 and 2025, respectively.
To-date, we have not experienced any delivery or non-performance issues from our suppliers, nor any degradation in the quality of fuel we have received, and we are closely monitoring developments from the conflict. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Other Key Business Drivers for more information on the Russia and Ukraine conflict.
To-date, we have not experienced any delivery or non-performance issues from our suppliers, nor any degradation in the 77 Table of Contents quality of fuel we have received, and we are closely monitoring developments from the conflict. See ITEM 7.
Commodity Price Risk Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental, regulatory and environmental policies, and other factors.
After the separation on February 1, 2022, reporting on risk management issues is to the Executive Committee and the Audit and Risk Committee of the Board of Directors. Commodity Price Risk Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental, regulatory, and environmental policies, and other factors.
Maturities Within Total Fair Value 2023 2024 2025 2026 2027 2028 and Beyond Normal Operations, Commodity derivative contracts (a)(b) : Actively quoted prices (Level 1) $ 264 $ 169 $ 128 $ 68 $ 33 $ — $ 662 Prices provided by external sources (Level 2) 238 4 (83) 6 — — 165 Prices based on model or other valuation methods (Level 3) 284 (107) 83 38 7 (86) 219 Total $ 786 $ 66 $ 128 $ 112 $ 40 $ (86) $ 1,046 __________ (a) Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.
Maturities Within Total Fair Value 2024 2025 2026 2027 2028 2029 and Beyond Normal Operations, Commodity derivative contracts (a)(b) : Actively quoted prices (Level 1) $ 103 $ 90 $ 46 $ 9 $ (8) $ — $ 240 Prices provided by external sources (Level 2) (276) 186 91 (1) (1) — (1) Prices based on model or other valuation methods (Level 3) 712 133 (9) 9 1 23 869 Total $ 539 $ 409 $ 128 $ 17 $ (8) $ 23 $ 1,108 __________ (a) Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.
Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk. Interest Rate and Foreign Exchange Risk We use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. We may also utilize interest rate swaps to manage our interest rate exposure.
Interest Rate and Foreign Exchange Risk We use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. We may also utilize interest rate swaps to manage our interest rate exposure.
Trading and Non-Trading Marketing Activities The following table detailing our trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO). 78 Table of Contents The following table provides detail on changes in our commodity mark-to-market net asset or liability balance sheet position from December 31, 2020 to December 31, 2022.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Other Key Business Drivers for more information on the Russia and Ukraine conflict. Trading and Non-Trading Marketing Activities The following table provides detail on changes in our commodity mark-to-market net asset or liability balance sheet position from December 31, 2021 to December 31, 2023.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the February 2021 extreme cold weather event and Texas-based generating asset outages. Exchange Traded Transactions We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange ("the Exchanges"). The Exchange clearinghouses act as the counterparty to each trade.
Exchange Traded Transactions We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange (each an Exchange and, collectively, Exchanges). The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.
Removed
After the separation on February 1, 2022, reporting on risk management issues is to the Executive Committee, the Risk Management Committees of our generation and customer-facing businesses, and the Audit and Risk Committee of the Board of Directors.
Added
Beginning in 2024, our nuclear fleet is eligible for the nuclear PTC provided by the IRA, an important tool in managing commodity price risk for each nuclear unit not already receiving state support.
Removed
For merchant generation sales 77 Table of Contents not already hedged via comprehensive state programs, such as the CMC in Illinois, we typically utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant sales are hedged on an approximate rolling 90%/60%/30% basis.
Added
The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted annually for inflation over the duration of the program. In locations and periods where our load serving activities do not naturally offset existing generation portfolio risk, remaining commodity price exposure is managed through portfolio hedging activities.
Removed
We may also enter transactions that are outside of this ratable hedging program. As of December 31, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation.
Added
Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation.
Removed
Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options.
Added
During this prompt three-year period, we seek to mitigate price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter transactions that further optimize the economic benefits of our overall portfolio.
Removed
Equivalent sales represent all hedging products, which include economic hedges, CMC payments, and certain non-derivative contracts. A portion of our hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions.
Added
Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure is the risk of a change in the value of unhedged positions.
Removed
Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. We actively manage our portfolio to mitigate market price risk exposure for our unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in our portfolio.
Added
Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products.
Removed
See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2022 and 2021.
Added
Our employee benefit plan trusts also hold investments in equity and debt securities. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates for sensitivity analysis of key assumptions in the valuation of our Pension and OPEB obligations. 80 Table of Contents
Removed
First, the table provides the source of fair value used in determining the carrying amount of our total mark-to-market net assets (liabilities), net of allocated collateral.
Removed
Second, the table shows the maturity, by year, of our commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash.
Removed
The following tables provide information on our credit exposure for all derivative instruments, NPNS, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2022.
Removed
The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties.
Removed
The figures in the table below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, and commodity exchanges, which are discussed below.
Removed
Rating as of December 31, 2022 Total Exposure Before Credit Collateral Credit Collateral (a) Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure Investment grade $ 1,304 $ 135 $ 1,169 — $ — Non-investment grade 110 88 22 — — No external ratings Internally rated—investment grade 106 — 106 — — Internally rated—non-investment grade 374 40 334 — — Total $ 1,894 $ 263 $ 1,631 — $ — 80 Table of Contents __________ (a) As of December 31, 2022, credit collateral held from counterparties where we had credit exposure included $152 million of cash and $111 million of letters of credit.
Removed
Maturity of Credit Risk Exposure Rating as of December 31, 2022 Less than 2 Years 2-5 Years Exposure Greater than 5 Years Total Exposure Before Credit Collateral Investment grade $ 1,276 $ 7 $ 21 $ 1,304 Non-investment grade 108 2 — 110 No external ratings Internally rated—investment grade 106 — — 106 Internally rated—non-investment grade 227 104 43 374 Total $ 1,717 $ 113 $ 64 $ 1,894 Net Credit Exposure by Type of Counterparty As of December 31, 2022 Investor-owned utilities, marketers, power producers $ 1,311 Energy cooperatives and municipalities 112 Financial Institutions 9 Other 199 Total $ 1,631 Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physical or financial contracts for the sale and purchase of electricity, natural gas, and other commodities.

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