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BPA, WAPA and Trinity Public Utilities District take steps to help mitigate wildfire threat

June 9, 2021

by Peter Maloney
APPA News
June 9, 2021

With the onset of wildfire season in the western United States, the Bonneville Power Administration (BPA), the Western Area Power Administration (WAPA) and California’s Trinity Public Utilities District (PUD) recently detailed steps they are taking to help mitigate the potential of significant wildfires.

BPA earlier this month added a public safety power shutoff (PSPS) procedure to its wildfire mitigation plan, and Trinity Public Utilities District is partnering with staff at the Sierra Nevada region office of the Western Area Power Administration (WAPA) to make its transmission rights of way less vulnerable to wildfires.

While the number of acres burned year-to-date is below the 10-year average, historically low precipitation levels have raised the risk of significant wildfires to above normal, according to the National Interagency Fire Center. More than 87 percent of the western U.S. is now categorized in drought and over half the West is in the highest two categories of drought.

BPA began considering a PSPS procedure in the fall of 2020 after last summer’s Northwest wildfire season.

“This procedure is another preventative measure layered on top of world-class vegetation management, strategic asset management and risk-based planning – the cornerstones of our mitigation efforts,” BPA Administrator John Hairston said in a statement.

BPA said customer feedback helped inform the PSPS process it has put in place for the 2021 fire season. The utility also noted that taking a BPA transmission line out of service does not necessarily mean Northwest residents and businesses will lose power.

“BPA is committed to providing as much prior notification as possible to customer utilities, generators and state emergency managers, particularly when PSPS will result in service interruptions,” Tina Ko, BPA vice president of transmission marketing and sales, said in a statement.

“Because weather is one of the variables involved, our notification windows may be compressed at times,” Ko said, “however, we will do everything we can to help customers and emergency management officials plan for the lack of electricity these events can cause.”

For Trinity PUD, wildfire mitigation is taking the form of expanding power line rights of way.

The PUD is expanding the right of way of its 60-kilovolt (kV) Trinity-to-Weaverville line from 80 feet to up to 130 feet. It is also expanding its Lewiston 60-kV tap line right of way from 80 feet to up to 130 feet, and expanding the rights of way for its distribution lines from 20 feet to up to 130 feet. The expansions aim to reduce fuel loads and to create potential firebreaks.

Recent wildfires have shown that the current minimum buffer clearances are not sufficient to prevent destructive wildfires, Trinity PUD said.

Trinity PUD’s aim is to protect its transmission and distribution system through “proactive vegetation management,” which the PUD said would also “enhance the reliability of power distribution, improve WAPA transmission line access and protect the health and safety of nearby communities and biological and natural resources.”

Trinity PUD and WAPA’s systems run through areas with dense vegetation and steep terrain. CalFire has classified the area a “very high fire hazard.”

California law, specifically Senate Bill 901, requires publicly owned electric utilities to prepare wildfire mitigation measures if the utilities’ overhead electrical lines and equipment are located in an area that has a significant wildfire risk.

California PUC seeks comments on new PSPS guidelines

Meanwhile, the California Public Utilities Commission (CPUC) is seeking public comment on a proposal that would enhance and update existing guidelines and rules for utility PSPS events in advance of the 2021 wildfire season.

 The proposed decision, which is on the agenda for the CPUC’s June 24 meeting, states that when utilities de-energize transmission lines as a wildfire mitigation strategy of last resort they must balance the risk of harm from utility-ignited wildfires against the public harm of shutting off power.

 The proposal recommends guidelines and rules intended to augment existing directives to address some of the issues that arose during the utilities’ execution of PSPS events in 2020.

If adopted, the guidelines and rules would go into immediate effect and require annual reporting to increase transparency into electric investor-owned utilities’ (IOUs) planning and execution of PSPS events by requiring them to submit an annual pre-season report detailing actions taken to prepare for and mitigate the impacts of future PSPS events and to submit an annual post-season report providing data on customer-focused outcomes during prior year PSPS events.

To improve planning and preparation, the proposal would require IOUs to conduct annual PSPS exercises using the same procedures they would use in an actual PSPS event. The proposal would also include additional entities under the definition of “critical facilities and infrastructure” to ensure that entities essential to public safety receive advance notification of PSPS events and additional assistance in assessing the need for backup generation to ensure resiliency.

NYPA, EPRI awarded $200,000 to research long-duration storage

June 9, 2021

by Paul Ciampoli
APPA News Director
June 9, 2021

The New York Power Authority (NYPA) is launching a project with the Electric Power Research Institute (EPRI) to explore the use of crushed rock thermal energy storage to provide energy storage in a market with significant renewable energy resources.

The project, led by EPRI and funded by a $200,000 U.S. Department of Energy grant, will investigate the feasibility of a thermal energy storage (TES) technology developed by Brenmiller Energy. Another $50,000 will be funded by the project participants.

If determined to be feasible, the investigation team will pilot the technology and evaluate its ability to provide energy storage at NYPA’s Eugene W. Zeltmann Power Project in Astoria, N.Y.

Brenmiller, an Israeli developer and manufacturer of thermal energy storage systems, has patented a high-temperature crushed-rock TES system, which is being tested in three generations of demonstration units at separate sites globally.

The first phase of the project will be a feasibility study on the integration of the crushed-rock thermal energy storage into a range of fossil generation assets, which is expected to be complete in early 2022. 

A project plan would be developed for a second phase that would evaluate real world operating conditions and demonstrate the technology’s ability to provide effective and economical energy storage at a natural gas combined cycle plant.

The plan is to evaluate the cost and performance of Brenmiller’s TES technology, to support commercial-scale deployment by 2030.

As part of its Vision2030 strategic plan, NYPA is investigating the potential for low- to zero-carbon technologies at several of its facilities to help transition New York State from fossil fuel generation and stabilize the grid as it integrates cleaner sources of energy.

NYPA is also partnering with Brenmiller on a separate project to develop and demonstrate a TES-based combined heat and power (CHP) system at Purchase College (State University of New York) in Harrison, N.Y., to increase energy efficiency and reduce greenhouse gas emissions. That unit is expected to be operational later in the summer of 2021.

Additional information about Brenmiller is available here.

Artificial intelligence project looks to improve energy storage dispatch

June 8, 2021

by Peter Maloney
APPA News
June 8, 2021

Independent power producer Vistra is using artificial intelligence (AI) software developed by a team at the University of Texas at Dallas (UT Dallas) to help it better predict wholesale power market prices in California.

Vistra is using the software to project electricity prices for its soon-to-be 400-megawatt (MW) Moss Landing energy storage facility in Monterey County, Calif.

Vistra’s Moss Landing project is one of four energy storage projects awarded power purchase agreements with Pacific Gas and Electric in 2018 through a solicitation designed to find alternatives to renewing reliability-must-run contracts for gas-fired projects owned by Calpine that serve the South Bay area in California.

The software was developed by researchers from the University of Texas at Dallas who applied statistical and machine-learning methods to build models that Vistra is now using to predict near real-time bid and sell prices in California’s wholesale power market to enable it to buy electricity to charge the Moss Landing batteries at the lowest price and sell the stored energy at the most economically opportune time.

The joint project, which was funded by Vistra, was “crucial to optimizing electricity pricing at the Moss Landing battery farm that came online in early 2021, Rachit Gupta, vice president at Vistra and lead sponsor of the project, said in a statement. “The project was a tremendous success, and we are extremely happy that we availed ourselves of a great source of expertise that is present locally.” The software helps Irving, Texas, based Vistra make more precise pricing projections, Gupta said.

Its work for Vistra was the inaugural project for the Center for Applied AI and Machine Learning (CAIML) at UT Dallas’ Erik Jonsson School of Engineering and Computer Science. The center was established in 2019 to work with industry partners to apply advanced research in AI and machine learning to solve practical problems.

The UT Dallas researchers completed work on the AI project in August 2020 and held classes from December through February to train Vistra employees in the background technologies.

“AI can help a company like Vistra forecast future generation and demand on load, wind and solar energy, and optimize bidding, scheduling and deployment of energy to improve profitability and market participation,” Feng Chen, associate professor of computer science at UT Dallas and the project’s principal investigator, said in a statement.

Power sector increasingly looking at AI

The electric power industry is increasingly looking at AI for ways to solve difficult problems or improve the performance of complex systems. In March, the Electric Power Research Institute (EPRI) held a roundtable on AI in the power sector.

The roundtable was one of several EPRI hosted in its effort to foster collaboration between the power and AI industries through its AI.EPRI project.

Public power utilities, such as CPS Energy, are among the utilities exploring the uses of AI and machine learning. The San Antonio, Texas, utility is machine learning to improve its demand management and is starting to use the technology to improve its vegetation management programs.

In 2019, Salt River Project in Arizona signed a deal to use AI to improve its information technology operations. And in New York, the New York Power Authority (NYPA) is working with software vendor C3 IoT to use AI to help meet its energy efficiency targets.

In April, APPA received its third patent related to its efforts to help ensure that public power utilities have long-term access to advanced analytical technologies for business-related decision making.

TVA issues solicitation for solar, battery storage proposals

June 8, 2021

by Paul Ciampoli
APPA News Director
June 8, 2021

The Tennessee Valley Authority (TVA) is interested in procuring up to 200 megawatts (MW) of new stand-alone renewable energy resources or renewable energy plus battery energy storage systems (BESS), including all the associated environmental attributes, TVA said in a request for proposals issued on June 8.

TVA is also interested in procuring BESS for existing utility scale solar projects signed as a result of 2017, 2019 or 2020 renewable energy RFPs with power purchase agreements (PPA) that do not have BESS currently.

All resources must be located in the TVA service territory or delivered to TVA’s interface with neighboring transmission systems. If any proposal is delivered to the TVA interface, it must have all of the cost components included for an all-in energy price.

TVA said it reserves the right to vary from this target energy quantity based on evaluation of bids that are received. Any transaction resulting from the RFP will be in the form of a PPA.

Proposals must be submitted by July 20, 2021 and TVA will announce the selected projects this winter.

TVA said the RFP supports TVA’s Green Invest program, which has secured solar farms to meet the renewable energy goals of auto manufacturers, data centers, local power companies, cities, and universities. Since 2018, Green Invest has attracted nearly $2.7 billion in solar investment and procured about 2,100 megawatts of solar.

Jeff Lyash, President and CEO of TVA, discussed the Green Invest program in a recent episode of the American Public Power Association’s Public Power Now podcast.

The RFP is available here.

Department of Energy seeks to cut cost of hydrogen by 80%

June 8, 2021

by Paul Ciampoli
APPA News Director
June 8, 2021

The Department of Energy (DOE) on June 7 launched an effort to reduce the cost of clean hydrogen by 80% to $1 per kilogram in one decade.

The initiative is part of the newly launched DOE Energy “Earthshots Initiative,” which DOE said aims to accelerate breakthroughs of more abundant, affordable, and reliable clean energy solutions within the decade.

DOE noted that currently hydrogen from renewable energy costs about $5 per kilogram. By achieving the 80% cost reduction goal, “we can unlock a five-fold increase in demand by increasing clean hydrogen production from pathways such as renewables, nuclear, and thermal conversion,” DOE said.

The announcement followed Secretary Jennifer Granholm’s commitment, made during President Biden’s Leaders Summit on Climate, to propel next-generation technologies in key clean energy sectors. The Energy Earthshots effort will drive integrated program development across DOE’s science, applied energy offices, and ARPA-E to address tough technological challenges and cost hurdles, and rapidly advance solutions to help achieve climate and economic competitiveness goal, according to DOE.  

As part of the launch, at the DOE’s Hydrogen Program Annual Merit Review and Peer Evaluation Meeting, DOE’s hydrogen program issued a request for information (RFI) on viable hydrogen demonstrations. 

Topics in the RFI include: 

Responses are due July 7, 2021, by 5 p.m. ET.

For more information about the RFI, visit EERE Exchange. 

Additional information on DOE’s efforts to enable at-scale clean hydrogen is available here.

APPA issues new report on hydrogen

The American Public Power Association this week released a report on hydrogen that offers a perspective on where the emerging hydrogen market is in the U.S. and globally, what is driving the growing interest in hydrogen and what obstacles are preventing hydrogen technology from being able to scale-up.

Topics covered in the report include:

The report is available for free to members of APPA.

White House memorandum outlines best practices to protect against ransomware

June 7, 2021

by Paul Ciampoli
APPA News Director
June 7, 2021

The Biden Administration on June 2 issued a memorandum to corporate executives and business leaders that outlines the U.S. government’s recommended best practices to guard against the threat of ransomware.

The memo was sent by Anne Neuberger, Deputy Assistant to the President and Deputy National Security Advisor for Cyber and Emerging Technology.

“The most important takeaway from the recent spate of ransomware attacks on U.S., Irish, German and other organizations around the world is that companies that view ransomware as a threat to their core business operations rather than a simple risk of data theft will react and recover more effectively,” she wrote. “To understand your risk, business executives should immediately convene their leadership teams to discuss the ransomware threat and review corporate security posture and business continuity plans to ensure you have the ability to continue or quickly restore operations.”

The memo outlines several steps that should be taken now to address the threat of ransomware.

First, it recommends implementing the five best practices from President Biden’s Improving the Nation’s Cybersecurity Executive Order.

Second, the memo recommends backing up data, system images, and configurations, regularly testing them, and keeping the backups offline. “Ensure that backups are regularly tested and that they are not connected to the business network, as many ransomware variants try to find and encrypt or delete accessible backups. Maintaining current backups offline is critical because if your network data is encrypted with ransomware, your organization can restore systems.”

It also recommends updating and patching systems promptly. This includes maintaining the security of operating systems, applications, and firmware, in a timely manner. “Consider using a centralized patch management system; use a risk-based assessment strategy to drive your patch management program.”

Testing of incident response plans should also occur. “There’s nothing that shows the gaps in plans more than testing them. Run through some core questions and use those to build an incident response plan: Are you able to sustain business operations without access to certain systems? For how long? Would you turn off your manufacturing operations if business systems such as billing were offline?”

In addition, the memo highlights the need to check a security team’s work and recommends using a third party to test the security of systems and the ability to defend against a sophisticated attack. Many ransomware criminals are aggressive and sophisticated and will find the equivalent of unlocked doors, the memo notes.

The memo also recommends segmenting networks. “There’s been a recent shift in ransomware attacks – from stealing data to disrupting operations. It’s critically important that your corporate business functions and manufacturing/production operations are separated and that you carefully filter and limit internet access to operational networks, identify links between these networks and develop workarounds or manual controls to ensure Industrial Control System (ICS) networks can be isolated and continue operating if your corporate network is compromised. Regularly test contingency plans such as manual controls so that safety critical functions can be maintained during a cyber incident.” 

Ransomware is a very familiar threat to the public power segment of the industry and APPA held a webinar on April 21 of this year, with the Cybersecurity and Infrastructure Security Agency. The slide deck and the recording can be accessed here. Additionally, the Electricity Information Sharing and Analysis Center (E-ISAC) in February of this year released a report labeled Ransomware Trends for Utilities and APPA encourages public power utilities to review this resource.

APPA continues to stress the importance of public power utilities joining the E-ISAC for timely and actionable sharing of threats to the electricity subsector. Currently, the E-ISAC is specifically designing a portal and report for small and medium sized public power and cooperative utilities.  To learn more about the E-ISAC and how to join, visit the E-ISAC website or contact E-ISAC Member Services or the public power address below.

Any questions can be directed to: cybersecurity@publicpower.org.

FERC staff releases white paper on hybrid resources, seeks feedback

June 5, 2021

by Peter Maloney
APPA News
June 5, 2021

Staff at the Federal Energy Regulatory Commission (FERC) on May 26 issued a notice inviting comments on hybrid resources, such as solar power combined with energy storage, and, at the same time, released a white paper on the subject.

The deadline for submitting comments to FERC is Aug. 18, 2021.

The white paper discusses the hybrid resources technical conference FERC held in July 2020, as well as the information garnered from comments.

Interest in hybrid resources has accelerated in recent years, in part because of recent growth in electric storage resources, the white paper noted.

Hybrid resource deployment has increased in both Regional Transmission Organization (RTO) and Independent System Operator (ISO) and non-RTO/ISO regions, with growth concentrated in certain areas, most notably in the California Independent System Operator Corporation (CAISO) region, according to the white paper.

As recently as two years ago, there were virtually no hybrid resources in interconnection queues, and there are now 102 gigawatts (GW) of solar paired with storage, and 11 GW of wind paired with storage in interconnection queues across the country, including both RTO/ISO regions and non-RTO/ISO regions, the FERC paper said.

The white paper cited comments from the American Wind Energy Association (AWEA) stating that 10 percent of resources in RTO/ISO interconnection queues nationwide are hybrid projects.

In California, CAISO reports that 47.6 percent of active interconnection requests are for hybrid resources. For requests submitted to CAISO in 2020, the number rises to 58 percent.

The vast majority of announced hybrid projects are solar photovoltaic (PV) combined with battery electric storage, but project developers have also announced wind combined with electric storage, natural gas-fired generation combined with electric storage, and solar power combined with wind and electric storage projects, the white paper said.

Citing data from Lawrence Berkeley National Laboratory, the white paper noted that solar combined with energy storage made up about 85 percent of the capacity of hybrid resources in the interconnection queues nationwide at the beginning of 2020.

In its definition of “hybrid,” the white paper included co-located resources that are modeled and dispatched as two or more separate resources that share a single point of interconnection and integrated hybrid resources that share a single point of interconnection and are modeled and dispatched as a single resource.

One driver of the increase in hybrid resources is that some configurations allow the electric storage component to qualify for increased financial incentives, including the federal Investment Tax Credit and certain state incentives for electric storage resources that charge from renewable resources, the white paper said.

Those incentives, combined with the potential for wholesale market revenues could attract further investment in hybrid technologies and projects, potentially leading to increased competition and market efficiency, the white paper said, noting that at the beginning of 2020, the six RTOs and ISOs under FERC jurisdiction had more than 62 GW of hybrid projects in their interconnection queues.

FERC noted that in comments several participants emphasized the need for flexibility at all stages of the co-located hybrid and integrated hybrid project lifecycle, including with respect to whether a hybrid project will operate as a single or multiple resource type, changes during the interconnection process, and assessing how the resource can operate in the market most economically.

FERC also noted that some commenters stressed the need for hybrid resources to be able to provide all services that they are capable of providing and said that market power mitigation approaches may need to be modified.

In its analysis in the white paper, FERC said the record in its hearings to date demonstrate “co-located hybrid and integrated hybrid resources can add value to the electric grid” by allowing intermittent or duration-limited resources to achieve a higher combined capacity factor, facilitate more efficient transmission system operation by reducing congestion and curtailment in areas with high penetrations of intermittent resources, and provide transmission providers with more controllable ancillary services than standalone intermittent resources. Combining resource types also allows for the sharing of permitting, siting, equipment, and interconnection costs.

Nonetheless, FERC noted that the rapid growth of hybrid resources presents challenges to RTOs and ISOs and other FERC-jurisdictional transmission providers and federal and state regulators to keep up with the pace of technological change. And while RTOs and ISOs have begun to make changes to their wholesale electric markets, much remains to be addressed, FERC said in the white paper.

With additional experience RTOs, ISOs and transmission providers “will be better able to address issues including a potential need to modify interconnection rules, modeling approaches in interconnection and reliability models, market participation rules such as bidding and modeling, and capacity valuation methods,” FERC said.

The notice seeking comments is available here.

NREL report highlights how electrification increases the need for demand flexibility

June 5, 2021

by Peter Maloney
APPA News
June 5, 2021

Demand-side flexibility can support widespread electrification and a renewables-based power grid by providing operating reserves throughout the year thus reducing the need for natural gas plants and energy storage to fill in demand gaps, according to a new report from the National Renewable Energy Laboratory (NREL).

Increasing demand-side flexibility reduces the number of low-load hours for fossil fuel generators and reduces the number of starts and shutdowns of natural gas generators, resulting in up to $10 billion in annual operating cost savings in scenarios with the greatest demand-side flexibility, according to the report, Operational Analysis of U.S. Power Systems with Increased Electrification and Demand-Side Flexibility.

The report is the sixth and final in NREL’s Electrification Futures Study (EFS) that was launched in 2017 to explore the potential impacts of widespread electrification in all U.S. economic sectors.

The EFS researchers found that demand-side flexibility—mainly from optimized vehicle charging and flexible operations of end-use equipment in buildings and industry—can alleviate the challenges of operating a highly electrified power system with high levels of variable renewable generation.

Shifting load to align with wind and solar generation reduces the risks of unserved energy and the curtailment of renewable resources, NREL said, adding that the complementary relationship between flexible electric vehicle charging and solar generation is particularly pronounced.

In modeled scenarios with high electrification and high variable renewables, demand-side flexibility can lower annual carbon dioxide (CO2) emissions by 8.3% by enabling greater utilization of renewable energy and avoiding fossil fuel consumption, the studies found.

For the EFS project, NREL analysts ran simulations of the national power system, using hourly operations, operational costs, and emissions to study the interactions between different levels of electrification, demand-side flexibility, and renewable energy deployment.

The analysts examined hourly power system operation without demand-side flexibility to test whether electrification — and associated changes in annual energy demand, hourly demand, operating reserve requirements, and the capacity mix — affects the grid’s ability to serve load or operating reserves.

The simulations showed the future power systems envisioned in the EFS can serve nearly 100% of load and 100% of operating reserves with no demand-side flexibility, but energy storage would be critical to balance load and provide operating reserves. Expanded power transfer capability across regions would also be needed to meet increased electrified demand.

The results showed “the importance of all sources of grid flexibility — including transmission and inter-regional power transfers, flexible generation, storage, and demand-side sources of flexibility — will likely be important for operating a power system with high electrification and high renewable energy deployment,” Trieu Mai, NREL analyst and EFS principal investigator, said in a statement.

In the final EFS report, NREL analysts examined how flexible loads change system operations with electrification.

They found that by shifting the timing of electricity demand, demand-side flexibility can provide operating reserves throughout the year, reducing the need for other generation sources such as natural gas plants and energy storage.

“Ultimately, the analysis highlights the value of increased integration and coordination of demand- and supply-side resources in future electric system planning and operations—particularly under high electrification futures,” Ella Zhou, NREL analyst and lead author of the final report, said in a statement.

The NREL analysts also noted that additional research is needed on flexible load operation, cost, and value across a wide range of subsectors and end uses, including assessments of grid reliability in a highly electrified system.

NREL has scheduled a June 17 webinar to discuss the findings of its EFS project and the need for further study.

NYPA providing $39 million for New York City electric bus chargers

June 5, 2021

by Peter Maloney
APPA News
June 5, 2021

The New York Power Authority (NYPA) said it has finalized a $39 million agreement to install 67 overhead chargers for New York City buses.

Under the agreement, NYPA will provide and install 66 overhead chargers capable of charging a total of 60 buses at four Metropolitan Transit Authority (MTA) depots in Staten Island, Brooklyn, Queens, and Manhattan, as well as an overhead on-street “pantograph” charger at Williamsburg Bridge Plaza in Brooklyn.

A pantograph charger is mounted on an overhead, on-street structure that mates with electrical contacts on a bus’ roof. It provides enough charge during drivers’ rest periods to keep the bus operating for two shifts per day.

Installing chargers overhead allows them to operate with buses from a variety of manufacturers.

The new infrastructure will help support the MTA’s commitment to purchase only electric buses starting in 2028 and to have an all-electric 5,800-bus fleet by 2040. It also supports New York Gov. Andrew Cuomo’s goal of having the five largest transit operators in the state electrify their transit fleets by 2035.

MTA and its local operator, New York City Transit, has about 25 electric buses and funding approval for another 500 electric buses in the agency’s 2020-2024 capital plan.

In late May, the MTA said it plans to purchase 60 electric buses this year, a 33 percent increase over its previous plan to purchase 45 electric buses.

Design and engineering work on the overhead chargers at the bus depots began last month.

Construction is expected to begin this fall, with the project expected to be completed within a year so that the chargers will in operation when the MTA’s next round of electric bus purchases arrives in third-quarter 2022.

ABM and Verdek have signed contracts to help complete the project. The charging hardware is being supplied by ABB and Siemens.

The overhead chargers at the depots will have power levels ranging from 150 kilowatts (kW) to 300 kW. The on-street charger will have a power level of 500 kW.

“Modernizing our public transportation infrastructure is a significant step toward the full electrification of the transportation sector that will remove polluting vehicles from our roadways,” Gil Quiniones, NYPA president and CEO, said in a statement. “Together with the MTA, we will promote a cleaner environment, improve public health and ensure a sustainable future for all New Yorkers.”

Public power utilities are playing a key role in the electrification of public transportation.

Last October, the Seattle City Council approved Seattle City Light’s Transportation Electrification Strategic Investment Plan, enabling the utility to move ahead with its transportation electrification strategy, which includes customer-facing incentives and out-reach and electrification enablement, such as the development of infrastructure needed to support transportation electrification.

Los Angeles is also transitioning to an emissions-free bus fleet, and the Los Angeles Department of Water and Power is working with the city’s Department of Transportation (LADOT) and MTA Transit to coordinate deployment plans. LADWP has so far helped LADOT install 255 charging stations to support 510 electric buses by 2028 and has created a fleet rate structure for electric fleet vehicle charging.

In Vermont, Burlington Electric Department and Green Mountain Transit in January unveiled two electric-powered buses.

In Florida, Orlando’s transit agency, LYNX, added eight electric buses to serve fare-free downtown circular routes.

And in 2015, Seneca, South Carolina, became the first city in the country to have a totally electric bus system when it deployed five battery-electric buses and two fast charging stations.

Report sees role for small modular reactors in Washington State’s clean energy transition

June 2, 2021

by Peter Maloney
APPA News
June 2, 2021

Small modular nuclear reactors (SMRs) could play a key role in Washington State’s mandated transition to a clean energy economy, according to a new report by researchers at the Pacific Northwest National Laboratory (PNNL) and the Massachusetts Institute of Technology.

Washington’s Clean Energy Transformation Act, enacted in 2019, calls for the elimination of coal-fired generation by 2025, aims to reach carbon dioxide (CO2) neutrality by 2030, and requires that the state’s power sources must generate electricity without emitting greenhouse gases by 2045.

The phasing out of coal- and natural gas-fired generation, which supplied about 17 percent of the state’s fuel mix in 2018, will leave a roughly 5-gigawatt (GW) gap in generation capacity that SMRs could help fill, according to the report, “Techno-economic Assessment for Generation III+ Small Modular Reactor Deployments in the Pacific Northwest.”

The report analyzed five case studies combining two SMR technologies and three potential sites. The study evaluated deployment of NuScale-designed plants, each containing 12 SMR units delivering roughly 600 megawatts (MW) to 700 MW at three different sites, and deployment of GE-Hitachi (GEH)-designed SMR plants delivering roughly 300 MW at two different sites.

The first case analyzed deployment of NuScale SMRs at the Idaho National Laboratory in Idaho Falls, Idaho, as a potential site for the Utah Association of Municipal Power Systems’ (UAMPS) Carbon Free Power Project. In January, UAMPS and NuScale signed an agreement to facilitate the development of a nuclear plant at the site.

In May, the Grant County Public Utility District signed a memorandum of understanding with NuScale to evaluate the deployment of the company’s SMR technology in central Washington.

The second case looked at using NuScale SMRs at a site near Energy Northwest’s Columbia nuclear plant in eastern Washington.

The third case studied placing a GE-Hitachi SMR at the Idaho National Laboratory site using the same cost reductions as the NuScale plant. The fourth and fifth cases evaluated using NuScale and GE-Hitachi designs, respectively, at the Big Hanaford coal-fired plant in Centralia in western Washington that is scheduled to close its coal-fired units in 2025.

The analysis indicated that in a future CO2 free electricity sector deployment of advanced SMRs would be competitive with Levelized Costs of Electricity (LCOEs) in the range of $51 per megawatt hour (MWh) to $54/MWh for the NuScale design and in a range of $44–$51/MWh for the GE-Hitachi design.

Each of the three sites also provides additional advantages, according to the report. There is already existing infrastructure and a workforce trained in the operation of conventional and nuclear plants in place in eastern Washington, and the Centralia site has existing grid connections that could be tapped, as well as a workforce that could be shifted from the closing coal-fired units.

The authors noted that they used two different means of calculating LCOE. For NuScale, they used the company’s current design. For GE-Hitachi, they used that company’s design-to-cost methodology with target pricing that is being confirmed as the design matures.

The findings “show that advanced small modular reactors could be economically competitive in a future carbon-free electricity sector,” Ali Zbib, PNNL’s manager for nuclear power systems and a co-author of the report, said in a statement. “They’re well-suited to play an important role in an energy market that requires more flexibility.”

The report noted that advanced SMRs can operate continuously at full power to provide baseload energy or can follow power swings on the grid. The report also found that electricity demand in Washington can fluctuate significantly on a monthly, daily and even five-minute basis, noting that average daily demand in February 2019 varied by more than 2,100 MW.

The report also noted, however, that near-firm renewable resources, such as wind power coupled with energy storage, “may provide competition to SMR generation.” The report cited a 1-MW, 150-MWh storage system developed by Form Energy in Minnesota that will provide Great River Energy with dispatchable wind power.

And, given the relatively short development time for such projects “and their relatively inexpensive power, they may provide stiff competition to the longer permitting to generation time paths for SMRs.”

At current prices, the cost of long-term storage “is prohibitively high to keep the lights on using only variable renewable energy,” the report found.

Lithium ion batteries cost approximately $200 per kilowatt hour (kWh) for approximately 4 hours of storage, the authors noted. They cited a MIT study indicating that storage costs could need to be as low as $20/kWh for long-term storage to be feasible.

Nonetheless, renewable energy still suffers from its variability and, even with its comparably low cost compared with firm power alternatives, “it fails to provide the flexibility required to meet long duration periods when wind and sun are not providing adequate electricity,” the report said.

While wind and solar will play a critical role, phasing out carbon-emitting resources sparks the need for flexible, non-carbon-emitting sources, and “nuclear energy can be an integral part of a clean energy portfolio that will allow the state of Washington to meet its clean energy objectives,” Zbib said.

The report is available here.