B. Recent Commission Nominees
President Biden recently nominated Annie Caputo and Bradley Crowell to fill the two vacancies on the Commission. Annie Caputo previously served on the Commission from 2018 to 2021. Prior to her time on the Commission, she served as a professional staff member and policy advisor for the U.S. Senate Environment and Public Works (Senate EPW) Committee. Bradley Crowell previously served as Director of Nevada’s Department of Conservation and Natural Resources under both Republican and Democratic governors and spent time in the Department of Energy (DOE) handling congressional affairs during the Obama Administration. Mr. Crowell also served as a policy advisor for Senator Whitehouse on the Senate EPW Committee. The Senate EPW Committee held a hearing on June 8, 2022, to consider the nominations of both Ms. Caputo and Mr. Crowell. It is expected that a vote will be scheduled on both nominations before the end of July 2022.
C. Federal Policy Developments
1. Civil Nuclear Credit Program
The most significant development in federal policy was enactment of the Infrastructure Investment and Jobs Act (Public Law 117-58), otherwise known as the Bipartisan Infrastructure Law (BIL), which became law in November 2021. The law established infrastructure planning for micro and small modular reactors and created the civil nuclear credit program (CNCP) to prevent early closure of existing nuclear generation due to poor financial performance. DOE stood up a program to allocate credits to financially struggling certified nuclear reactors. Once DOE certifies an eligible nuclear reactor, the reactor must then submit a bid that describes the price of the desired credits, not to exceed the projected average annual operating loss. The BIL appropriated $6 billion to DOE for fiscal years 2022 through 2026, with $1.2 billion for fiscal year 2022.
In April 2022, DOE issued guidance on the CNCP, giving direction on how nuclear reactors may apply for funding. Shortly thereafter, DOE revised its guidance to open up the credits to reactors that recover more than fifty percent of its costs from cost-of-service regulation or regulated contracts, so long as “a material amount of its total revenue from sources that are exposed to electricity market competition.” This change was requested by the governor of California, who has expressed interest in reversing course on plans to shut down both units at Diablo Canyon Power Plant (a rate-regulated plant) in 2024 and 2025. DOE applications are due September 6, 2022.
2. Nuclear Production Tax Credit
During this reporting period, lawmakers continue to consider a production tax credit (PTC) to support existing merchant nuclear plants. In June 2021, the House and Senate introduced legislation (H.R. 4024/S. 2291) to establish a nuclear PTC for existing facilities. The bill was incorporated into the House Democrats’ Green Energy Tax Title as part of the budget reconciliation process (previously referred to as the Build Back Better proposal (H.R. 5376, § 136109)). However, the bill has neither been passed nor has a standalone nuclear PTC bill.
The proposal would award a $15/MWh refundable PTC to generation from existing merchant nuclear plants, which is the tax-credit amount currently provided to new wind generation. The PTC would be reduced eighty percent for every dollar in revenue that a plant receives above $25/MWh. It also imposes limits to prevent double-dipping by nuclear units that receive state-level support and would be subject to certain labor requirements. While the proposal in the original legislation allowed for a six-year PTC, some members of Congress have expressed support for a ten-year PTC.
3. Federal Government Climate Initiative
On December 8, 2021, President Biden issued the Executive Order on Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability, which sets forth a goal for the Federal Government to procure one hundred percent carbon-free electricity on a net annual basis, including fifty percent twenty-four/seven carbon free electricity, by 2030. Nuclear energy is included as carbon-free electricity.
D. State Policy Developments
1. Illinois—Climate and Equitable Jobs Act
Illinois passed the Climate and Equitable Jobs Act (CEJA) on September 15, 2021, to decarbonize the Illinois energy sector by requiring privately owned coal plants to close by 2030 and municipally owned coal plants to be one hundred percent carbon free by the end of 2045. Privately owned natural gas plants must close by 2045, and municipally owned natural gas plants must close by 2045 unless converted to green hydrogen or similar technology. CEJA expressly recognized that nuclear energy is “necessary” to the state’s one hundred percent clean-energy goal. As such, it created a carbon mitigation credit program to support continued generation from three existing nuclear plants in Illinois. A carbon mitigation credit is a tradable credit that represents the carbon emission reduction attributes of one megawatt-hour of energy produced from a nuclear power plant in the PJM Interconnection. The law sets maximum bid prices for each year of the statutory program (2022–2027) and directs that any federal support be included in the plant’s revenue calculations.
2. Pennsylvania Regional Greenhouse Gas Initiative (RGGI)
On April 23, 2022, Pennsylvania became the twelfth state to join the RGGI in an effort to meet its goal of reducing (from 2005 levels) carbon emissions eighty percent by 2050. RGGI is a cooperative, market-based effort among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia to cap and reduce carbon emissions from the power sector. The Pennsylvania Department of Environmental Protection issued a rule to establish a program to limit carbon dioxide emissions from certain fossil fuel-fired electric generating units and establish the state’s participation in RGGI. The state’s nuclear generators benefit from RGGI because the program’s cap and trade approach sets a regulatory limit on carbon emissions from fossil-fuel electricity generators and permits trading of carbon emissions, which values the carbon-free attributes of the nuclear power generators. Pennsylvania’s decision to join RGGI contributed to keeping at least one nuclear power facility from retiring prematurely.
E. Decommissioning
1. Decommissioning Rulemaking
On March 3, 2022, the NRC published a proposed rule entitled Regulatory Improvements for Production and Utilization Facilities Transitioning to Decommissioning. This proposed rule represents the first proposed comprehensive revision in decades to the NRC’s decommissioning regulations. Because several commercial power reactors have recently shut down and others have now completed decommissioning, the rule is intended to leverage that recent experience to provide a more defined path for reactors transitioning from operations to decommissioning.
The proposed rule’s publication came four months after the Commission approved its publication in SRM-SECY-18-0055, almost four years after the NRC staff first sought Commission approval in SECY-18-0055, and over seven years after the rulemaking process began. The delay between Commission approval and publication was, in large part, due to Commission-directed changes to the proposed rule to provide additional opportunities for external stakeholders (e.g., licensees, state and local governments, interested members of the public) to comment on the NRC’s oversight process for individual reactor decommissioning projects. As NRC Chairman Christopher Hanson acknowledged in his voting record, the effect of this expansion of the public participation process could “delay decommissioning activities and in turn postpone use of the remediated sites . . . after the conclusion of” decommissioning.
The proposed rule covers the following major topics: (a) emergency preparedness; (b) physical security; (c) cybersecurity; (d) drug and alcohol testing; (e) Certified Fuel Hander definition and elimination of the Shift Technical Advisor; (f) decommissioning funding assurance; (g) offsite and onsite financial protection requirements and indemnity agreements; (h) environmental considerations; (i) record retention requirements; (j) low-level waste transportation; (k) spent fuel management planning; (l) backfitting; (m) foreign ownership, control, or domination; (n) scope of license termination plan requirement; (o) removal of license conditions and withdrawal of orders made redundant by regulation; and (p) changes for consistent treatment of holders of combined licenses and operating licenses. The NRC also released four corresponding draft guidance documents for public comment, including one proposed new guidance document on Emergency Planning for Decommissioning Nuclear Power Reactors, and revised versions of three existing regulatory guides on Decommissioning of Nuclear Power Reactors, Assuring the Availability of Funds for Decommissioning Production or Utilization Facilities, and Standard Format and Content for Post-Shutdown Decommissioning Activities Report.
NRC extended the comment deadline through August 30, 2022. As of the date of this report, more than 225 comments have been submitted. Based on its current schedule, the NRC Staff anticipates completing its comment-review process and sending a final rule package to the Commission by October 2023. It estimates that the final rule will be published in May 2024.
2. Decommissioning Industry Trends
Among recently shutdown facilities, the asset transfer model continues to be the most prevalent means of executing decommissioning, particularly for merchant facilities. Under this approach, the incumbent utility transfers the shutdown facility, NRC licenses, decommissioning liability, and decommissioning trust funds to a new company to carry out the decommissioning, typically on a more accelerated schedule than a traditional SAFSTOR schedule out to the sixty years allowed by NRC regulations. The major decommissioning participants that have emerged with the recent wave of plant retirements have been made up of industry vendors who already specialize in key workstreams for decommissioning: Holtec International, EnergySolutions, and Northstar-Orano make up the group of new licensees that have acquired plants entering decommissioning.
The main regulatory drivers for this decommissioning model have mostly been based on state and local stakeholder engagement. In some states with recently shutdown facilities, a combination of public utility regulators, attorneys general, environmental agencies, legislatures, and local tax jurisdictions have engaged with outgoing utilities and incoming decommissioning companies to assert state and local interests related to funding, schedule, non-radiological remediation standards, and future land use. These stakeholders often participate to some degree in the NRC licensing process; however, in most states, existing processes afford state and local input into the decommissioning process. NRC’s review of the corresponding license transfers has remained focused on the adequacy of radiological decommissioning funding, spent fuel management funding, and technical wherewithal (without the operational component). Regarding licensees spent fuel management plans, NRC staff has shown a bit more willingness to credit future DOE recoveries, which have become more predictable over the years, although staff continue to require backstops to ensure that licensees can reasonably cover spent fuel storage operation and maintenance costs in the event DOE recoveries are not as predictable as they anticipate.
F. New Nuclear Developments
1. Vogtle Unit 3 Approaches 10 C.F.R. § 52.103(g)
Georgia Power Company and Southern Nuclear Operating Company expect to receive NRC authorization under 10 C.F.R. § 52.103(g) to load fuel in Vogtle Unit 3 later this year. The § 52.103(g) finding requires completion of all ITAAC in the Vogtle Unit 3 Combined License (COL) issued under the NRC’s Part 52 framework. Vogtle Unit 3 will be the first reactor to achieve this milestone under this regulatory framework, which was designed in part to frontload regulatory approvals and hearing opportunities. Vogtle Unit 3 received one ITAAC petition under the Part 52 framework, but no contentions were admitted to the hearing. The § 52.103(g) finding will represent the final major regulatory stage-gate for the first new nuclear unit in decades to startup and begin commercial operations.
2. 10 C.F.R. Part 53 Advanced Reactor Licensing Framework Rulemaking
NRC has continued progress on its rulemaking, Risk Informed, Technology-Inclusive Regulatory Framework for Advanced Reactors (to be codified as 10 C.F.R. pt. 53) for advanced nuclear reactor licenses. The staff initiated its efforts in 2020 and has been developing and intermittently releasing preliminary proposed rule language for public review and comment and holding public meetings with stakeholders and the Advisory Committee on Reactor Safeguards (ACRS). The preliminary proposed Part 53 language has evolved to include two distinct licensing framework options. Framework A includes requirements that would support an iterative approach to design and licensing in which a probabilistic risk assessment is used in a leading manner. It leverages principles developed as part of the industry-led Licensing Modernization Project described in NEI 18-04, Revision 1, and NRC Regulatory Guide 1.233. Framework B allows a more traditional approach to design and licensing in which deterministic safety analyses are complemented by risk insights. It also provides for the optional use of an Alternate Evaluation for Risk Insights approach if certain criteria are satisfied to demonstrate that a bounding accident of such a facility would be of very low consequence.
The NRC staff plans to complete development of the fully consolidated version of the proposed Part 53 rule by the end of September 2022 to support the ACRS full committee meeting on the proposed rule in October 2022 and to issue the proposed rule for further public comment in early 2023. The Commission has directed the staff to publish the final Part 53 rule by July 2025.
3. Advanced Nuclear Reactor GEIS (SECY-21-0098)
Perhaps the most important NRC rulemaking initiative aimed at expediting the environmental review process for advanced nuclear reactors (ANRs) is the development of an ANR generic environmental impact statement (GEIS). In December 2021, the staff released SECY-21-0098, seeking Commission approval to publish a proposed rule that would amend 10 C.F.R. Part 51 to codify the findings of the NRC’s ANR GEIS. The December 2021 draft ANR GEIS (NUREG-2249) uses a technology-neutral regulatory framework and performance-based approach to determine those environmental impacts that could result in the same impacts for different ANR designs that fit within the parameters set forth in the ANR GEIS (Category 1 impacts) and those environmental impacts that would require a project-specific analysis (Category 2 impacts). Specifically, the draft ANR GEIS uses a plant parameter envelope (PPE) that consists of bounding values or parameters, and assumptions, for specific reactor design features regardless of the site, as well as a set of generic site parameters, termed the site parameter envelope (SPE). The GEIS presents generic analyses that evaluate the possible impacts of an advanced reactor that fits within the bounds of the PPE on a site that fits within the bounds of the SPE. The NRC staff is seeking to issue the final ANR GEIS and associated Part 51 revisions by January 2024.
G. Subsequent License Renewal Developments
The NRC has issued renewed licenses authorizing ninety-four reactors to operate for up to sixty years, and, in 2018, plant operators began to apply for subsequent license renewal (SLR) to allow operation for up to eighty years. NRC previously prepared a GEIS for license renewal based on experience gained from reactor operations.
In February 2022, the Commission issued orders that have significant practical implications for licensees that have obtained, or are seeking to obtain, SLR. The Commission, by a 2–1 vote, reversed a 2020 ruling and held that the GEIS applies only to the initial license renewal (i.e., from forty to sixty years) and does not address SLR environmental impacts. Consequently, the Commission directed the NRC staff to review and update the GEIS so that it also specifically covers operations during SLR. Additionally, the Commission directed the NRC staff to modify two previously approved SLR applications to shorten the license terms to match the end dates of the previous licenses (i.e., initial renewed licenses) while the NRC staff completes its SLR National Environmental Policy Act (NEPA) analyses. The Commission also indicated that it will not issue any further SLRs until the NRC staff has completed an adequate NEPA review for each SLR application. Effectively, this decision means that current and near-term applicants have two options: (1) wait for the NRC to update the GEIS so it can be applied in their SLR proceeding, or (2) review the generic issues covered by the GEIS on a site-specific basis to assist the NRC in preparing an expanded site-specific impact statement. Although the NRC is targeting an accelerated twenty-four-month schedule to update the GEIS and related regulations, some applicants are electing to proceed with site-specific reviews.
