Skip Navigation

Small Modular Reactor Technology Delivers Reliability, Resiliency, Safety and Affordability

November 22, 2022

by Peter Maloney
APPA News
November 22, 2022

New nuclear technologies, such as small modular reactors (SMR), have reached a point where they are able to help utilities address growing concerns about fulfilling their core mission: delivering safe, affordable, and reliable electric power.

Several industry trends are challenging utility executives’ abilities to balance those three key objectives.

A July report from the North American Electric Reliability Corp. (NERC) highlighted the growing threats to reliability, including extreme weather events, the growing proliferation of “inverter based resources” such as photovoltaic solar power and energy storage, and increasing reliance on natural gas-fired generation.

The growth of renewable resources aimed at meeting state and federal goals aimed at addressing greenhouse gas emissions has been impressive. In the first half of the year, 24 percent of utility-scale generation in the United States came from renewable sources, according to the Energy Information Administration. However, as NERC pointed out this summer, as renewable resources have proliferated, gas-fired generators are becoming “necessary balancing resources” for reliability, leading to an interdependence that poses “a major new reliability risk.”

In this environment, if utilities are going to stay on track to meet their clean energy targets while providing secure, safe and reliable electric power to meet growing demand, they are going to need a new solution.

“NuScale Power’s SMR technology offers a carbon-free energy solution with features, capability, and performance not found in current nuclear power facilities,” Karin Feldman, Vice President of NuScale’s Program Management Office, said in an interview.

Several utilities have already begun exploring the potential of a new generation of nuclear technology to help them meet both their clean energy and reliability needs as they work toward meeting growing demand.

NuScale’s project portfolio includes a six module, 462-MW VOYGR™ SMR power plant. Utah Associated Municipal Power Systems (UAMPS) plans to develop at the Department of Energy’s (DOE) Idaho National Laboratory in Idaho Falls for their Carbon Free Power Project (CFPP).

NuScale also has memorandums of understanding to evaluate the deployment of its SMR technology with Associated Electric Cooperative in Missouri and Dairyland Power Cooperative in Wisconsin.

“What we bring to the table is a technology that is smaller and simpler; that lowers total costs while providing high reliability and resilience, and greater safety,” said Feldman, who develops and manages NuScale’s portfolio of projects and establishes and maintains project controls, cost estimating, and risk management standards. She is also NuScale’s primary interface with the DOE.

Cost Comparisons

The smaller scale of NuScale’s reactors – 77 MW versus 700 MW or even 1,600 MW or more for conventional reactors – brings several cost advantages, Feldman said. Smaller reactors can be fabricated in a factory, which is cheaper than field fabrication, because it involves repetitive procedures that foster iterative improvement and economies of scale, she said. Smaller reactors also take less time to build, which lowers construction costs.

Because they are modular, an SMR does not force a utility to commit to participation in a nuclear project in the 1,000-MW to 2,000-MW size range. An SMR project can be scaled to meet demand, and modules can be added as demand requires, Feldman said. That helps reduce financial risk for a utility, she said.

Another, related consideration, highlighted by the supply chain disruptions in the wake of the COVID-19 pandemic, is that much of NuScale’s technology can be locally sourced. “We are taking advantage of the U.S. supply chain to the greatest extent possible,” Feldman said. “We have some overseas manufacturers, but we are also engaged to develop additional U.S. capabilities in areas such as large-scale forgings.”

Reliability and Resiliency

Nuclear power plants generally have high reliability, over 92 percent, nearly twice the reliability of coal and natural gas plants, but the smaller, compact design of SMR technology can offer additional reliability advantages, Feldman said. Because NuScale plants are designed to scaled up in incremental steps, if any one of the individual reactors has an issue, the other reactors can continue to generate power, she explained.

NuScale’s SMR technology also enhances resiliency, Feldman said. The design calls for the reactors to be housed in a building below grade, hardening their vulnerability to airplane strikes and very large seismic events, she said.

An SMR plant also is designed with black start capability so that it can restart after a disruption without using the surrounding electric grid. “So, in the event of an emergency, it could be a first responder to the grid, one of the first generators to start up,” Feldman said.

And because the design calls for multiple reactors, a problem with one reactor does not require the entire plant to shut down. An SMR plant can also operate in island mode, serving as a self-sufficient energy source during an emergency, Feldman said.

In some ways, a NuScale SMR power plant resembles a microgrid. In fact, NuScale’s technology team has done a lot of analysis on microgrid capacity, Feldman said, noting that the analysis found that a 154-MW SMR plant could run for 12 years without refueling. “The technology is very good for mission critical functions and activities,” she said.

Safety First

Cost and resiliency are important considerations, but if a power plant, especially a nuclear power plant, is not safe, other considerations pale in comparison.

Safety is built into NuScale’s SMR design, Feldman said. “The SMR has a dual walled vessel design that gives it an unlimited coping period,” she said. “If an incident does occur, the plant can shut down without operator intervention or action and be safe and secure,” she said.

NuScale’s integrated design encompasses the reactor, steam generators and pressurizer and uses the natural action of circulation, eliminating the need for large primary piping and reactor coolant pumps.

If needed, the reactor shuts down and self cools indefinitely without the need for either alternating current or direct current power or additional water. The containment vessel is submerged in a heat sink for core cooling in a below grade reactor pool housed in a Seismic Category 1 reactor building as defined by the U.S. Nuclear Regulatory Commission (NRC). In essence, the unit continues to cool until the decay heat dissipates at which point the reactor is air cooled, Feldman said.

In 2018, the NRC found that NuScale’s SMR safety design eliminates the need for class 1E power, that is, power needed to maintain reactor coolant integrity and remain in a safe shutdown condition.

In August 2020, the NRC approved the overall design of NuScale’s SMR. In a next step, the NRC in July directed staff to issue a final rule certifying NuScale’s SMR design.

If approved, the certification would be published in the Federal Register and have the effect of law, providing even greater comfort to any entities exploring SMR technology to provide clean, emission free, reliable and affordable power, Feldman said.

The rulemaking is on NRC’s docket for a decision in November.

Finally, after a rigorous years long review by the NRC, the Final Safety Evaluation Report (FSER) regarding NuScale’s Emergency Planning Zone (EPZ) methodology was issued. This is another tremendous “first” for NuScale’s technology. With the report’s approval of our methodology, an EPZ that is limited to the site boundary of the power plant is now achievable for a wide range of potential plant sites where a NuScale VOYGR™ SMR power plant could be located.

Delays Slow Clean Energy Installations by 55 Percent in Second Quarter

November 22, 2022

by Peter Maloney
APPA News
November 22, 2022

Clean energy installations dropped 55 percent in the second quarter compared with the same period in 2021, slowed in part by widespread delays, according to a new report from the trade group American Clean Power.

There were 3,188 megawatts (MW) of utility-scale clean energy capacity installed in the quarter, making it the lowest quarter for clean energy capacity additions since third quarter 2019, according to the Clean Power Quarterly Market Report.

The only technology that saw an increase was energy storage, which rose 13 percent. Solar installations were down 53 percent compared with first-quarter 2021. And onshore wind installations were 78 percent lower in the second quarter compared with the same time period last year, the report said.

“Many projects continue to face supply chain-related challenges,” the report’s authors said. “Availability of solar modules has significantly delayed schedules for projects following the Department of Commerce’s decision to investigate duty circumventions claims,” They added.

In March, the Department of Commerce launched an investigation into whether certain photovoltaic solar cells and modules imported from Southeast Asia are circumventing U.S. tariffs.

Solar power projects comprised 64 percent of delayed projects with land-based wind projects accounting for 23 percent of delayed capacity and storage 13 percent, the report found. And project delays continue to mount, the report said, noting that developers reported 19,286 MW of projects that experienced delays in the second quarter, including 8,116 MW that is now expected online this quarter. Multiple projects, totaling 827 MW, have had more than one delay in their expected online dates, according to the report.

The delays reported in the second quarter were compounded by previous slowdowns, the report found, noting that at the end of 2021, 10,993 MW of clean power capacity experienced delays, of which only 3,850 MW has since come online.

Additionally, in the first quarter of 2022, 7,370 MW of capacity was delayed, of which 551 MW has since come online. In all, since the end of 2021 more than 32,400 MW of capacity has been delayed and has not yet achieved commercial operation, the report found.

Of the 8,166 MW of clean energy capacity expected online in the second quarter but was delayed, 5,782 MW are now expected online by year end with the remaining 2,400 MW of capacity now expected online between 2023 and 2026 or to be delayed indefinitely, the report said.

Looking forward, the capacity of solar power in the clean energy pipeline slowed compared with the first half of 2021, but showed a 5 percent increase over the first quarter, the report found. Solar power projects now account for 57 percent of the pipeline of clean energy capacity in the pipeline, including 22,765 MW under construction and 50,938 MW in advanced development.

Development of land-based wind power, the largest source of operational clean power, has also slowed down, the report found. Between third-quarter 2021 and fourth-quarter 2021 wind capacity in the development pipeline decreased by 7 percent, and between the end of 2021 and first-quarter 2022 the land-based wind pipeline decreased 2 percent, and in the second quarter the wind project pipeline decreased by 1 percent.

Land based wind projects now account for 18 percent, or 23,185 MW, of the clean energy project pipeline with offshore wind projects accounting for an additional 14 percent, or 17,502 MW, of the pipeline.

Energy storage projects also slowed, decreasing by 1 percent in terms of megawatt capacity since the first quarter and down from an 18 percent increase between fourth-quarter 2021 and first-quarter 2022, the report found. At the end of the second quarter there were 14,499 MW (36,200 megawatt hours) of storage capacity in development, according to the report.

In terms of megawatts, 31 percent of battery storage capacity in the pipeline are standalone projects with the remaining 69 percent of projects paired with wind or solar resources, according to the report.

California leads in battery storage development with 5,773 MW, accounting for 41 percent of the total storage pipeline, the report found. Texas ranks second with 2,415 MW, and Nevada third with 1,473 MW.

California also ranked first in terms of overall clean energy development, bringing 825 MW of clean energy online in the second quarter, the report found. Texas was second, installing 618 MW, followed by Florida with 277 MW, and Georgia with 236 MW.

In terms of technology, 1,575 MW of new solar capacity was brought online in the second quarter, bringing 2022 solar installations to 4,558 MW, the report said. Five land-based wind projects came online in the second quarter with a total capacity of 620 MW. Total 2022 wind installations are now 3,485 MW. And battery storage had a record second quarter with 992 MW coming online, bringing year-to-date total to 1,751 MW.

DOE Announces Conditional Selection of Calif. Nuclear Plant to Receive Funding

November 21, 2022

by Paul Ciampoli
APPA News Director
November 21, 2022

The U.S. Department of Energy (DOE) on Nov. 21 announced the conditional selection of the Diablo Canyon nuclear power plant in California to receive the first round of funding from the Civil Nuclear Credit (CNC) Program.

Units 1 and 2 at the Diablo Canyon Power Plant (DCPP) were scheduled to be decommissioned in 2024 and 2025, but the conditional award of credits, valued at up to $1.1 billion, creates a path forward for Diablo Canyon to remain open. Final terms are subject to negotiation and finalization by DOE.

Funded by President Biden’s Infrastructure Law, the $6 billion CNC program aims to help preserve the existing U.S. nuclear reactor fleet.

DOE noted that shifting energy markets and other economic factors have resulted in the early closures of 13 commercial reactors across the United States since 2013.

Owned and operated by Pacific Gas and Electric Company (PG&E), Diablo Canyon produces approximately 16 GWh of electricity annually.

PG&E filed its application for federal funding on September 2, 2022, the same day California Governor Gavin Newsom signed Senate Bill 846 into law, seeking to extend operations at DCPP in San Luis Obispo County for five years beyond its current license expiration in 2025.

Last month, the state authorized a loan of up to $1.4 billion from the Department of Water Resources to PG&E to support extending operations at the plant. SB 846 further directed PG&E to pursue funds from DOE, and any other potentially available federal funds, to pay back the loan and lower costs for customers should the plant’s operating license be extended.

DOE said that the first CNC award cycle prioritized reactors facing the most imminent threat of closure, limiting applications to reactors that had already announced intentions to cease operations due to economic factors.

The second CNC award cycle will prioritize reactors that are projected to shut down due to economic factors within the next four years.

DOE is expected to begin accepting applications for the second cycle of CNC funding in January 2023.  

Click here for additional details about the CNC Program and the upcoming second award cycle.

APPA, Other Groups Urge Lawmakers to Appropriate $1 Billion for Distribution Transformers

November 21, 2022

by Paul Ciampoli
APPA News Director
November 21, 2022

Lawmakers should appropriate $1 billion this year for implementation of the Defense Production Act (DPA) to specifically address the supply chain crisis for electric distribution transformers, the American Public Power Association (APPA), the National Rural Electric Cooperative Association (NRECA), Edison Electric Institute (EEI), National Association of Home Builders (NAHB), Leading Builders of America (LBA), and Associated General Contractors of America (AGC), said in a Nov. 18 letter.

The letter was sent to Sen. Patrick Leahy, D-Vt., Chairman of the Senate Committee on Appropriations, Sen. Richard Shelby, R-Ala., Vice-Chairman of the Senate Committee on Appropriations, Rep. Rosa DeLauro, D-Conn., Chairwoman of the House Committee on Appropriations, and Rep. Kay Granger, R-Texas, Ranking Member, House Committee on Appropriations.

In June 2022, President Biden announced that he was invoking the DPA to accelerate the domestic production of certain clean energy technologies, which included grid components and distribution transformers. Under DPA authorities, DOE could rapidly support domestic manufacturing capacity through purchases of equipment or materials, financial assistance in capital to expand production lines, or making subsidy payments for the supply of high-cost materials. For DOE to utilize DPA authorities, it must receive a direct appropriation from Congress.

“Throughout 2022, the electric sector and representatives from residential and commercial building sectors have been calling attention to the unprecedented supply chain challenges both industries have been facing in procuring equipment used to maintain and grow the electric grid,” wrote APPA President and CEO Joy Ditto and leaders of the other groups.

“Specifically, electric utilities continue to have significant problems in procuring basic equipment – particularly distribution transformers – needed to operate the grid, provide reliable electric service, and restore power following severe storms and natural disasters. In housing construction, this is further exacerbating their ability to address the housing affordability crisis facing our nation.”

Due to the threats to reliability, the Electricity Subsector Coordinating Council (ESCC) established an industry “Tiger Team” to examine the supply chain crisis, the letter noted.

“Through this process, the electric industry has been able to report and confirm what individual utilities and the housing industry have been saying since late last year: that construction and electrification projects are now being deferred or canceled and that they are concerned about their ability to adequately respond to major storms due to depleted stockpiles,” the groups said.

The Tiger Team ultimately found that current transformer production is not meeting demand and that demand is expected to continue to increase in the coming years. Between 2020 and 2022, average lead times to procure distribution transformers across all segments of the electric industry and voltage classes rose 443 percent. The same orders that previously took two to four months to fill are now taking on average over a year. “This is a serious threat to reliability,” the groups said.

Among initial considerations for the federal government to address are labor shortages and material availability, which were identified as the most immediate short-term barrier to more manufacturing output. Additional long-term recommendations include building manufacturing capacity to support long-term demand and investing in domestic production of grain-oriented electrical steel (GOES), a key transformer component, the letter noted.

Usage of DPA authorities to address labor and material shortages, focused specifically on the production of distribution transformers, “is the most immediate way we can address this growing crisis. The upcoming work period is a critical opportunity to appropriate funds needed to help address these problems before the end of this year,” the letter said.

APPA is asking its members to reach out to their congressional delegation to support this appropriation request.

APPA Survey of Members Shows Distribution Transformer Production Not Meeting Demand and Shortages Pose an Urgent Threat

An APPA survey of its members shows that production of distribution transformers is not meeting current demand, “as evident in the significantly growing lead times, lack of stock in yards and the high number of project deferrals,” APPA said. Utilities are reporting low or near zero emergency stock, often used to recover post-disaster or do infrastructure maintenance. Electric reliability is under severe threat with demand increasing, lead times growing, and stockyards emptying.

APPA’s Joy Ditto Voices Concerns About Potential Railroad Strike in Letter to President Biden

November 21, 2022

by Paul Ciampoli
APPA News Director
November 21, 2022

In a Nov. 18 letter to President Biden, Joy Ditto, President and CEO of the American Public Power Association (APPA), voiced concerns about the potential for a strike by railroad workers, saying that a work stoppage would “seriously threaten” the reliability of electric grids in public power communities.

“I write to add the American Public Power Association’s (APPA) voice to the chorus of great concern being expressed regarding the ongoing railroad labor negotiations and the potential for a strike,” wrote Ditto.

“Public power utilities rely on railroads to receive fuel, chemicals, and other equipment necessary to provide their communities with essential electric service. A work stoppage would seriously threaten the reliability of the electric grids in their communities, as well as further pressure already strained supply chains and increase prices at a time of already high inflation,” she said.

For months, APPA has been calling attention to the enormous challenges our members are facing in procuring basic equipment to provide electric service and to restore service following storms and natural disasters.

“Distribution transformers pose a particularly acute problem; our members are now facing lead times of more than a year for delivery and, in many cases, are being limited in the number they are allowed to purchase,” wrote Ditto.

Transformers are also necessary to extend electric service to new homes, businesses, and communities, she noted. “Prices have also gone up precipitously. As not-for-profit electric utilities, increased equipment costs are shouldered directly by our customers. A rail work stoppage on top of these already formidable supply chain challenges would be calamitous.”

Ditto said APPA appreciates the hard work the Biden Administration put into averting a strike in September “and we urge all parties to redouble efforts to avoid a strike now.”

Comment Period Opens on Proposal to Add Reliability Mechanism to Texas Market

November 17, 2022

by Peter Maloney
APPA News
November 17, 2022

The Public Utility Commission of Texas (PUCT) is seeking comment on a report on reforms aimed at bolstering the reliability of the state’s wholesale electric market.

The report, Assessment of Market Reform Options to Enhance Reliability of the ERCOT System, includes “novel hybrid designs that maintain the unique” energy-only wholesale power market of the Electric Reliability Council of Texas (ERCOT). The study was done by Energy+Environmental Economics (E3).

The PUCT developed a Blueprint for Wholesale Market Design in response to legislation passed by Texas’ 87th Legislature, SB 3, calling for electric market reforms in the wake of the widespread outages and hundreds of deaths caused by Winter Storm Uri in February 2021.

The objective of the law, as regards generation reliability during extreme weather, is to set a reliability standard of a 1-in-10 loss of load expectation (LOLE) in order to establish sufficient reserves at all times and to provide a means of providing incentives for building new dispatchable generation.

Pursuant to the law, the PUCT agreed to develop tools to meet reliability needs not met by ERCOT’s real-time and ancillary services market. Phase II of the Market Design Blueprint adopted by the PUCT last December called for the commission to study hybrid designs that would maintain ERCOT’s energy-only energy market while providing incentives to ensure sufficient generation resources to meet reliability needs.

The recently released E3 report analyzed six proposed market design modifications and incorporated the results of over 35 hours of testimony and more than 300 written submissions received during the PUCT’s public comment period.

The PUCT was not, however, able to open for comment one design, the Performance Credit Mechanism (PCM), that emerged from the review and analysis process. The PUCT, therefore, opened a public comment period on the PCM option (Project 54335). The public comment period closes at noon on Dec. 15.

In addition to a status quo option, the reviewed market modification options included a Load Serving Entity Reliability Obligation (LSERO) that would require load serving entities to acquire reliability credits bilaterally from generators based on forward forecasts, a Forward Reliability Market (FRM) that would create a mandated, centrally cleared reliability market administered by ERCOT, a Backstop Reliability Service (BRS) that would authorize ERCOT to procure resources sufficient to meet reliability needs, and a Dispatchable Energy Credit (DEC) that would require load serving entities to procure credits equal to 2 percent of their annual load. The PCM would establish a process in which credits are awarded based on historic generation during periods of high stress on the grid.

The energy-only status quo scenario would result in a 2026 loss of load expectation of 1.25 days per year, far above the common industry standard of 0.1 days per year, and the exit of 11,260 megawatts (MW) of coal- and gas-fired generation capacity at a customer cost of $22.3 billion per year, according the E3’s analysis in the report.

The LSERO, FRM and PCM designs would result in the addition of 5,630 MW of incremental gas-fired capacity with a LOLE of 0.1 days per year and an annual cost of $460 million per year.

The BRS design would result in the addition of 5,620 MW and a LOLE of 0.1 days per year at an annual cost of $360 million. The DEC design would lead to an aggregate reduction in natural gas-fired generation, resulting in an LOLE of 2.03 days per year at an annual cost of $490 million, according to E3’s analysis.

The PCM design is similar to the LSERO and FRM designs but is less complex and avoids the need for forward looking accreditation, but generator revenues would be less stable under PCM and the design would be less able to less able to reflect infrequent extreme weather conditions, E3 said.

Multiple market designs in the report appear capable of improving market signals to ensure reliability, E3 said, but in the end the report’s authors recommended the FRM design as a “more suitable fit” for the ERCOT market that would “provide more natural year-to-year stability over market outcomes.” The PCM design, E3 said, would “entail significant risk because of its novelty.”

The PCM design has elements similar to the LSERO but “introduces features that may be more consistent with ERCOT market principles such as earned accreditation rather than an upfront administrative process,” PUCT staff said in the filing releasing the report and recommending the opening of the comment period on the PCM design.

Department of Energy Makes Nearly $350 Million Available for Long-Duration Energy Storage

November 17, 2022

by Paul Ciampoli
APPA News Director
November 17, 2022

The U.S. Department of Energy (DOE) recently announced nearly $350 million for emerging Long-Duration Energy Storage (LDES) demonstration projects.

The LDES Demonstrations Program will be managed by DOE’s Office of Clean Energy Demonstrations (OCED) and will fund nearly $350 million for up to 11 demonstration projects — projects that will contribute to the Department-wide goal of reducing the cost of grid-scale energy storage by 90% within the decade. DOE will fund up to 50% of the cost of each project.

The program aims to fund projects that will overcome the technical and institutional barriers that exist for full-scale deployment of LDES systems by focusing on a range of different technology types for a diverse set of regions.  

Letters of Intent are due by December 15, 2022, and full applications are due by March 3, 2023. Additional funding opportunities may follow this announcement to validate and accelerate commercialization of LDES technologies.  

In October, DOE issued a $30 million Lab Call Announcement for Long-Duration Energy Storage Demonstrations. Remaining funding for LDES programs will be covered at a later date. 

For more information on DOE’s Long-Duration Storage Shot initiative, click here. 

APPA Responds to FERC Proposals on Cybersecurity Rate Incentives

November 17, 2022

by Paul Ciampoli
APPA News Director
November 17, 2022

The Federal Energy Regulatory Commission (FERC) should reconsider several aspects of a Notice of Proposed Rulemaking (NOPR) on cybersecurity rate incentives including a proposal that would allow a 200-basis point return on equity (ROE) adder on eligible investments, the American Public Power Association (APPA) said in recent comments filed at FERC.

If the Commission allows an enhanced ROE on eligible investments, it should limit the incentive to 50 basis points, as the proposed 200-basis point adder is more than necessary to promote cybersecurity investment and could impose excessive costs on consumers, APPA said in its comments filed this month.

The comments responded to the FERC NOPR issued in September.

At the outset of its comments, APPA noted that it supports prudent utility investment to address the growing cybersecurity threats faced by the nation’s electric grid.  APPA also recognizes that, in adding section 219A to the Federal Power Act (FPA) Congress has directed the Commission to adopt incentive rate treatments (or performance-based rates) to promote certain cybersecurity-related investments. 

“While many features of the NOPR strike an appropriate balance between encouraging cybersecurity investment and protecting customers from unreasonable costs, APPA respectfully submits that certain aspects of the NOPR do not fully comply with the FPA’s requirements for incentive rate mechanisms, which remain fully applicable to any rule promulgated under section 219A.”

APPA urged the Commission to modify certain of the NOPR’s proposals while preserving the features of the NOPR designed to protect customers and ensure transparency.

NOPR Details

Under the NOPR, cybersecurity expenditures would be eligible for an incentive including both expenses and capital investments associated with advanced cybersecurity technology and participation in a cybersecurity threat information sharing program. 

Also, eligible cybersecurity expenditures would be voluntary and have to materially improve the utility’s cybersecurity posture. FERC proposes to establish a pre-qualified list of cybersecurity expenditures that are eligible for incentives that would be publicly maintained on FERC’s website.

The proposed incentives would take two forms: a return on equity adder of 200 basis points, or deferred cost recovery that would enable the utility to defer expenses and include the unamortized portion in its rate base, on which the utility could earn a return (the Regulatory Asset Incentive).

Approved incentives, with certain exceptions, would remain in effect for up to five years from the date on which the investments enter service or expenses are incurred.

Incentives Should Be Narrowly Tailored to Satisfy the Requirements of FPA Section 219A

Along with its concerns about the ROE adder proposal, APPA also said that FERC must ensure that there is a nexus between the incentives and project investment decision.

Such a requirement conforms the Commission’s regulations to precedent requiring the Commission, in awarding rate incentives under the just and reasonable standard, to see to it that the increase is in fact needed, and is no more than is needed, for the purpose, it said.

“Evaluating applications for incentives to ensure that there is a nexus between the incentive and the applicant’s investment decision is also necessary to verify that incentives are not awarded for actions that a utility has already taken or is already required to take,” APPA said.

While Congress has required FERC to adopt a rule providing incentives, the Commission, in designing such incentives, must conform to longstanding requirements for just and reasonable rate incentives, it said.

In considering the design of incentives under FPA section 219A, the Commission should also take into account evidence that lucrative incentives are generally unnecessary to promote cybersecurity investment, APPA argued.

The Commission Should Limit the Regulatory Asset Incentive to 50 Percent of Project Investment

APPA noted that in connection with the Regulatory Asset Incentive, the NOPR asks whether it would be preferable to permit only 50% of incentive-eligible expenses to be treated as regulatory assets.

“APPA encourages the Commission to adopt this change from the NOPR’s proposal to allow the entire qualifying expenditure to be accorded regulatory asset treatment.”

APPA also said that incentives should not be available for investments that utilities are required to make or that have already been made.

Southeast Energy Exchange Market Begins Operations

November 16, 2022

by Paul Ciampoli
APPA News Director
November 16, 2022

The Southeast Energy Exchange Market (SEEM) on Nov. 9 announced that it has initiated operations.

The new SEEM platform will facilitate automated, sub-hourly trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. Participation in SEEM is open to any entity that meet qualifying requirements. 

Founding members of SEEM include Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Progress, Georgia System Operations Corporation, Georgia Transmission Corporation, LG&E and KU Energy, MEAG Power, N.C. Municipal Power Agency No. 1, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Southern Company, and TVA. 

Four Florida energy companies – Duke Energy Florida, JEA, Seminole Electric Cooperative and Tampa Electric Company – have signed agreements to join as members of SEEM effective Jan. 1, 2023 and expect to initiate active energy trading in mid-2023. 

With their addition, the SEEM footprint would include 23 entities in parts of 12 states with more than 180,000 MW (summer capacity; winter capacity is nearly 200,000 MW) across two time zones.

TVA Pilot Program to Examine Installing Solar Projects at Closed Coal Ash Sites

November 16, 2022

by Paul Ciampoli
APPA News Director
November 16, 2022

The Tennessee Valley Authority (TVA) Board of Directors recently approved a pilot program to determine if closed coal ash sites are suitable for utility-scale solar projects.

Pending environmental reviews and regulatory approval, the $216 million pilot project would explore an innovative approach to repurpose a closed coal ash site at the Shawnee Fossil Plant to advance TVA’s clean energy efforts, TVA said.

TVA previously issued a request for proposals for conducting a Valley Decarbonization Study in calendar year 2023. The study is intended to model pathways to further reductions in emissions throughout the economy.

The Board recognized TVA’s fiscal year 2022 decarbonization initiatives guided by the agency’s strategic priorities and guiding principles: