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

December 13, 2022

by Peter Maloney
APPA News
December 13, 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.

PacifiCorp Agrees to Join California ISO’s Extended Day-Ahead Market

December 13, 2022

by Paul Ciampoli
APPA News Director
December 13, 2022

PacifiCorp, a utility which operates in six states, recently announced its plan to join the Extended Day-Ahead Market (EDAM) being developed by the California Independent System Operator (CAISO), as well as the Western Power Pool’s Western Resource Adequacy Program (WRAP).

PacifiCorp is the first utility to sign on to the new Western day-ahead market.

PacifiCorp noted that it has been working with the CAISO and a wide range of stakeholders to develop the new day-ahead market. The EDAM builds upon CAISO’s existing Western Energy Imbalance Market.

Plans call for the EDAM to begin operation in 2024, subject to federal regulatory approval.

The current real-time WEIM optimizes the energy imbalances throughout the West by transferring energy between participants in 15-minute and 5-minute intervals throughout the day. The proposed EDAM builds on this real-time market by extending optimization to a high volume of resource commitments that must be made a day in advance, which are then re-optimized in the real-time WEIM as conditions change. 

CAISO on Dec. 8 noted that the final EDAM proposal was released on December 7 and the CAISO Board of Governors and Western EIM Governing Body will be briefed on the proposal on December 14.

The final proposal will be brought forward to the CAISO Board of Governors and WEIM Governing Body for a decision under the joint authority decision framework on February 1 and filed with the Federal Energy Regulatory Commission later in 2023.

Pacific Power, a PacifiCorp division, serves customers in Oregon, Washington and California.

PacifiCorp is also joining the Western Resource Adequacy Program, which is managed by the Western Power Pool. PacifiCorp said it has worked extensively with the Western Power Pool and other potential participants in the development of the WRAP, which is expected to provide regionwide reliability benefits to it participants by pairing regional diversity with common resource adequacy standards. 

This means WRAP participants will be held to common planning standards to serve winter and summer peak loads. The common planning standards and increased regional collaboration will create a pool of resources that can be used to serve load, if needed, thus increasing reliability for the entire region.

Quidnet Awarded $10 Million to Fund CPS Energy Pumped Hydro Storage Project

December 13, 2022

by Peter Maloney
APPA News
December 13, 2022

Quidnet Energy has been selected to receive $10 million in funding from the Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) for a pumped hydro storage project the Houston company is developing for CPS Energy, the public power utility serving San Antonio, Texas.

Quidnet plans to use the ARPA-E funding to scale up its Geomechanical Pumped Storage (GPS) project to a 1-megawatt (MW), 10-megawatt hour (MWh) commercial system.

CPS Energy signed a 15-year capacity tolling agreement with Quidnet in March. The energy storage project could eventually be scaled up to as much as 15 MW.

CPS Energy said the project will support its “Flexible Path” Resource Plan to reduce net emissions by 80 percent by 2040.

Quidnet’s geomechanical technology stores energy by using renewable resources to pressurize water and store it underground in “storage lens” between layers of rock. The storage lens technology has been successfully demonstrated using different geologies across the United States, the DOE said.

Quidnet, which was co-founded by Microsoft co-founder Bill Gates, hopes to move its GPS technology from pilot scale to commercial scale by increasing the size of the storage lens, improving lens sealing, and commissioning the first grid-connected system. The company said the commercialization of the technology is aided by the fact that it uses existing drilling and hydropower machinery supply chains.

The funding for the GPS project falls under ARPA-E’s Seeding Critical Advances for Leading Energy technologies with Untapped Potential (SCALEUP) program, which provides further funding to previous ARPA-E teams that have been determined to be feasible for widespread deployment and commercialization.

Quidnet said its objective is to lower the cost of long-duration energy storage, that is, energy storage capable of providing 10 or more hours of electrical output, by 50 to 75 percent in an effort to make intermittent renewable energy sources more reliable and cost effective.

Maine’s Secretary of State Clears Path for Voters to Consider Public Power Utility in 2023

December 12, 2022

by Paul Ciampoli
APPA News Director
December 12, 2022

Maine’s Secretary of State Shenna Bellows in late November announced the completion of the certification of petitions that will allow voters in the state next year to consider replacing investor-owned utilities in Maine with a statewide, consumer-owned utility.

Bellows confirmed that 69,735 valid signatures were submitted for the initiative, enough to move forward to the November 2023 ballot.

The Maine Legislature will now consider this initiative, which would replace Central Maine
Power and Versant Power with a nonprofit, Maine-owned utility.

Legislators will have the opportunity to enact the bill as written or to send it forward to a statewide vote on the November 2023 ballot.

In October, a group in Maine called Our Power submitted more than 80,000 signatures from voters in 422 Maine towns.

Chelan PUD Commissioners Approve PUD Joining Resource Adequacy Program

December 12, 2022

by Paul Ciampoli
APPA News Director
December 12, 2022

Chelan PUD commissioners recently voted for the Washington State PUD to join the Western Resource Adequacy Program (WRAP), the first reliability planning and compliance program in the Northwest, which has been in the works since 2019.

About 26 utilities from Canada to northern California are participating in the voluntary, non-binding phase of WRAP.

Chelan said that while the Pacific Northwest typically produces abundant energy supply, “there are warning signs of a less certain future ahead: Increased demand for electricity, the rise of intermittent renewables like wind and solar, increased regulatory requirements, and more large-load industries moving to the West.”

WRAP has asked utilities to join the binding phase over the next several years, which means that utilities have guaranteed first priority to purchase energy from other member utilities in the event of a critical shortage. It also means that utilities may be subject to penalties if they don’t meet capacity requirements. The cost of joining is about $185,000 the first year, and $150,000 annually.

Chelan listed the benefits of WRAP as:

“If it doesn’t work out the way we anticipate, we can exit the program with a two-year notice at any time,” said Shawn Smith, Managing Director of Energy Resources.

SPP Takes Next Step in Expansion Of its Wholesale Market

December 12, 2022

by Peter Maloney
APPA News
December 12, 2022

The Southwest Power Pool (SPP) has taken the next step toward the centralization of day-ahead and real-time unit commitment and dispatch that the wholesale grid operator said would pave the way for the reliable integration of a rapidly growing fleet of renewable generation.

The Nov. 30 release of SPP’s detailed proposal for its Markets+ service provides the basis for stakeholders that expressed an interest in committing to Markets+ in December to formalize contractual commitments for phase one of the service.

Stakeholders interested in committing to funding further market development must sign a Markets+ Market Participant Phase One Funding Agreement by April 1, 2023, SPP said.

SPP has been working with western stakeholders since December 2021 to understand the features they would want in the grid operator’s proposed day-ahead and real-time market.

SPP describes Markets+ as “a conceptual bundle of services” that would centralize day-ahead and real-time dispatch using a hurdle-free transmission service across SPP’s footprint. “For utilities that see value in these services but who aren’t ready to pursue full membership in a regional transmission organization (RTO) at this time, Markets+ provides a voluntary, incremental opportunity to realize significant benefits,” SPP said.

SPP said it envisions a two-phase process for the continuing development of Markets+. In phase one, potential participants and stakeholders will financially commit to design the market protocols, tariff and governing documents. Phase two begins upon Federal Energy Regulatory Commission (FERC) approval. At that point, SPP would acquire necessary software and hardware while participating entities fully commit to fund and are integrated into the system.

Earlier in November, SPP announced the 2023 implementation of major components of the Markets+ governance structure and the exploration of a transitional real-time balancing market in 2024.

In August 2022, the Bonneville Power Administration became the first western utility to formally commit to funding further development of Markets+.

In September, Washington State’s Chelan County Public Utility District, Grant County Public Utility District, and Tacoma Power committed to Markets+. Arizona utilities, including Salt River Power also committed to Markets+ in September.

Interior Awards Five Leases for Offshore Wind in Northern California

December 12, 2022

by Peter Maloney
APPA News
December 12, 2022

The Bureau of Ocean Energy Management (BOEM), a division of the Department of the Interior (DOI), recently awarded five leases for offshore wind power development along the California coast.

The results of the BOEM lease sale represent the third major offshore wind lease sale this year and the first for the Pacific region, the DOI said. The sale drew competitive bids from five companies totaling $757.1 million, well exceeding the first lease sales that were held in the Atlantic, BOEM said.

The sale offered five lease areas covering 373,268 acres off central and northern California. The leased areas have the potential to produce over 4.6 gigawatts (GW) of wind energy, BOEM said.

The provisional lease winners are RWE Offshore Wind Holdings, California North Floating, Equinor Wind US, Central California Offshore Wind, and Invenergy California Offshore.

The lease sale included a 20 percent credit for bidders that committed to a monetary contribution to programs or initiatives supporting workforce training programs for the floating offshore wind industry, the development of a U.S. domestic supply chain for the floating offshore wind energy industry, or both. The DOI said the credit would result in over $117 million in investments.

The auction also included 5 percent credits for bidders that committed to entering community benefit agreements (CBA). One type of agreement is with communities, stakeholder groups, or Tribal entities whose use of the lease areas or use of the resources harvested from the lease areas is expected to be affected by offshore wind development. The second type of agreement is a general CBA with communities, Tribes, or stakeholders that are expected to be affected by the potential impacts on the marine, coastal or human environment from lease development.

Earlier this month, BOEM finalized two Wind Energy Areas (WEAs) in the Gulf of Mexico and said it planned to issue a proposed sale notice for the competition to lease the areas. The first WEA is approximately 27.6 miles off the coast of Galveston, Texas, and totals 508,265 acres. The second WEA is approximately 64.4 miles off the coast of Lake Charles, La., and totals 174,275 acres.

In February, the DOI announced the results of the nation’s highest-grossing competitive offshore energy lease sale in its history. The lease areas including oil and gas lease sales and six leases totaling more than 488,000 acres in the New York Bight for potential wind energy development, which drew winning bids from six companies totaling about $4.37 billion.

APPA’s Adrienne Lotto Emphasizes Importance of Layered Defenses for Grid Security

December 12, 2022

by Paul Ciampoli
APPA News Director
December 12, 2022

When it comes to grid security, the importance of layered defenses cannot be overstated, and while the power sector has a good overall understanding of the risk it is facing in this area, to the extent that more information can be shared from the federal government to entities and utilities, that is helpful for utilities to understand their risks and respond accordingly, said Adrienne Lotto, Senior Vice President of Grid Security, Technical & Operations Services, American Public Power Association (APPA), on Dec. 7.

She made her comments at a joint Department of Energy-Federal Energy Regulatory Commission supply chain risk management (SCRM) conference in Washington, D.C.

Lotto was a panelist at the conference that examined current supply chain risk management reliability standards, implementation challenges, gaps, and opportunities for improvement.

Other panelists were Jeffrey Sweet, Director of Security Assessments, American Electric Power, Shari Gribbin, Managing Partner, CNK Solutions, Scott Aaronson, Senior Vice President of Security and Preparedness, Edison Electric Institute, and Lonnie Ratliff, Director, Compliance Assurance and Certification, North American Electric Reliability Corporation.

Panelists were asked whether they think the currently effective supply chain risk management standards are sufficient to successfully ensure bulk power system reliability and security in light of existing and emerging risks to the cyber security supply chain.

“The simple answer is yes,” Ratliff said. “The standards provide a foundation to address and mitigate some of the supply chain challenges that we have across our industry. With this foundation, there’s always opportunities to improve so as we look at the effectiveness” of the standard, “NERC has taken several opportunities to assess those standards, bring up teams and evaluate the effectiveness and propose change to those standards.”

Lotto said that NERC and the power industry have shown a willingness to continue to partner and examine the NERC Critical Infrastructure Protection (CIP) standards as it relates to supply chain security and are continuing to do so.

As threats continue to evolve, the utility sector and NERC have also shown a willingness to evolve and take a second look at those standards and “that risk-based approach remains ongoing.”

At the same time, Lotto highlighted jurisdictional limitations to FERC “and the burden that that then places on the utilities trying to gain insight into the suppliers that they are utilizing in their systems.”  

“I do believe that the standards that are in place today are effective and are appropriate,” said Sweet. “They provide the flexibility for the utilities to be able to address the risks that they realize within their organizations.”

The supply chain risk management standard requires entities to have a supply chain risk management plan.

Supply Chain Risk Management Plan

Panelists were asked to address the question of whether it would be beneficial to provide additional clarity for the supply chain risk management plan in a couple of areas.

“One is in identifying and assessing risks,” said David Ortiz, Director of the Office of Electric Reliability at FERC. “Identifying triggers that would require activation of the plan and then requirements in that plan to respond to risks that are identified.”

Addressing the question of whether the power sector needs help in identifying and assessing risk, Lotto said, “the short answer is yes.”

She said that to the extent that more information can be shared from the federal government to entities and utilities, large or small, that is helpful for utilities to understand their risks and respond accordingly.

Lotto cautioned against an idea floated earlier in the conference that proposed throwing out the definition of high, medium and low in the risk-based approach currently being used at NERC.

She warned against making a holistic change in this approach. “The NERC CIPS standards are effective. They are working and that is sound risk management practice in any sector – to understand what your high, medium, low impacts are, so a holistic change like that at this time I think would actually set us back, as opposed to enable NERC to continue doing what it’s doing with the utilities and move us forward towards greater supply chain security.”

Prior to joining APPA, Lotto was vice president, chief risk and resilience officer at the New York Power Authority, where she led a team of risk management professionals.   

Meanwhile, Puesh Kumar, Director of the Department of Energy’s Office of Cybersecurity, Energy Security, and Emergency Response, noted that utilities “are trying to manage risk, but to do that they first need to understand the risk.”

He asked Lotto whether utilities “know the risk well enough and, if not, what are the gaps? What more could we be doing?”

Do utilities “have a good understanding of the risk that they’re managing to?”

“I would say holistically the answer is yes,” Lotto responded. There has been a “tremendous amount of work” done at the DOE, Department of Homeland Security, the Electricity Information Sharing and Analysis Center and the Multi State Information Sharing and Analysis Center “that helps to inform and provide industry insight into the risks. Now, that said, could we always do better? Of course.”

Lotto said that a recent incident involving an attack on Duke Energy substations in North Carolina “is a physical example where you see the risk in day-to-day life that the grid is exposed to, so continuing to foot stomp and provide situational awareness in a timely fashion with context and suggested solutions or guidelines, I think is important.”

She noted that APPA provides resources and guides and partners with the DOE through agreements “that enable us to do that. Particularly for the smaller members, it’s exceedingly helpful.”

EEI’s Aaronson said that “we understand the risk, but risk is always changing. Risk is a factor or a function of threat, likelihood and consequence.”

He said that “what is the consequence of something is also evolving, not just because the threat is evolving but the grid is constantly evolving.”

At a later point, Lotto emphasized the need for layered defenses when it comes to grid security. She said that while FERC and NERC have done a good job in addressing the baseline, the energy sector continues to collaborate, which includes discussing baselines and focusing on “getting even better and stronger.”

This continued coordination, not just in the regulatory arena, but also in terms of best practices, needs to continue to happen, she said.

“I think the greatest power that the federal government has is the power to convene,” Lotto said. Continuing to bring industry experts together with the federal government “to solve critical problems has to continue to evolve.”

She also said that the importance of economies of scale must not be overlooked “because individually we can’t do it alone. Our members can’t do it alone. The cyber threat, unfortunately, is advancing to the front lines where, fundamentally, our members are getting asked on a day-to-day basis to act as frontline defenders of networks and that’s an almost impossible task. They’re not set up to defend networks on a day-to-day basis from nation state adversaries that are attacking them.”

The power to convene at the federal government level, both through the NERC process “wherein they’re continuously looking and trying to evolve to meet the threat, together with best practices and advancing through groups that already exist or at the federal government level to achieve economies of scale and layered defenses is critical.”

ERCOT Creates Curtailment Program for Large Flexible Customers during Peak Demand Periods

December 10, 2022

by Paul Ciampoli
APPA News Director
December 10, 2022

The Electric Reliability Council of Texas (ERCOT) is implementing a voluntary curtailment program allowing large flexible customers, such as bitcoin mining facilities, to reduce their power use during periods of high demand, it said on Dec. 6.

“Our goal with this program is to work with large customers in supporting the reliability of the Texas power grid,” said Woody Rickerson, ERCOT Vice President of System Planning, in a statement. “These customers are large power users but have the flexibility and willingness to reduce their energy use quickly, if needed. By working with these large loads during peak demand periods, we will better serve all Texans while keeping the grid reliable and resilient.”

The program is primarily intended for large flexible customers, but any large customer directly connected to a transmission service provider’s facility can participate, subject to approval by ERCOT.

The program is temporary and completely voluntary until ERCOT establishes a long-term set of rules.

Registration for the program began on Dec. 6 and ERCOT anticipates the program going live in January 2023.

More information can be found in our Market Notice, including the registration form to participate.

Salt River Project Using Inflation Reduction Act to Build and Own Solar Plant

December 8, 2022

by Peter Maloney
APPA News
December 8, 2022

Arizona public power utility Salt River Project (SRP) is building a solar power project that will take advantage of recent changes in federal law that allows public power utilities to use tax benefits that were previously out of reach.

SRP’s board of directors recently approved the second phase of the 55-megawatt (MW) Copper Crossing Energy and Research Center in Florence, Ariz.

The utility-scale solar project is the first the utility is developing and will own and operate itself.

Historically, SRP has contracted for generation from renewable resources through power purchase agreements with developers that have access to federal tax credits for renewable energy projects.

The federal Inflation Reduction Act passed in August extended and expanded various energy tax incentives and gave public power utilities direct access to those credits by allowing allows public power utilities to receive direct federal incentive payments for renewable projects.

SRP said the change will give it greater ability to develop, operate and advance more renewable resources and potentially reduce costs for customers.

The first phase of the Copper Crossing project will add two natural gas-fired turbines with a total output of less than 100 MW, which SRP’s board approved in September. A third proposed phase for small-scale, long-duration energy storage system is expected to go to the utility’s board for approval in 2023.

SRP has not yet completed the design of the new solar portion of the Copper Crossing site. Engineering, material procurement and construction activities for the solar facility are expected to take approximately 24 months. The solar project is sited on land SRP owns next to its Abel substation adjacent to an existing 20-MW solar plant.

With this development and other recent awards, SRP is contracted for over 2,000 MW of our goal to add 2,025 MW of new utility-scale solar energy by 2025, SRP noted.