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Former Coal Plant Sites Get Second Life with Energy Storage Systems

September 11, 2023

by Paul Ciampoli
APPA News Director
September 11, 2023

Coal plant sites are becoming an increasingly attractive location for utility and energy storage development companies across the U.S. to site new energy storage systems.

Among the advantages of placing energy storage projects at coal plant sites is the ability to reuse existing infrastructure and grid interconnection rights.

Holyoke Gas & Electric Solar Plus Storage Project Built Next to Coal Plant Site

In 2018, ENGIE North America and Massachusetts public power utility Holyoke Gas & Electric unveiled a utility-scale energy storage system at a ceremony at the Mt. Tom Solar Farm in Holyoke, Massachusetts.

Owned and operated by ENGIE North America, the Mt. Tom energy storage system is a 3 MW/6 MWh utility-scale lithium-ion battery and the second such system to be installed in the state, which went commercial in 2018.

The battery draws power directly from the Mt. Tom Solar system, which is the largest community solar project in Massachusetts and is stored for use during peak demand periods.

The system is located adjacent to the former Mt. Tom Coal Plant along the Connecticut River, which ceased operation in 2014.

HG&E currently has a 20-year power purchase agreement with ENGIE.

“Since commercial operation commenced in 2018, the Mt Tom Solar + Battery Storage System continues to stabilize HG&E and ratepayer costs during periods of peak demand and volatile pricing, reduce stress on the local distribution infrastructure, and contribute to the regions low carbon goals,” Kate Sullivan Craven, Director of Marketing & Communications for Holyoke Gas & Electric, told Public Power Current.

“We appreciate ENGIE North America’s innovation that transformed the property into a state-of-the-art facility for the benefit of the local community,” she said.

“The people of Holyoke, Massachusetts, and our valued customer, Holyoke Gas & Electric, were on the vanguard in welcoming this pairing of technology into their community as we worked to transform the Mt. Tom site from coal to one producing power from solar + battery storage,” said Julie Vitek, Vice President, Government & Regulatory Affairs at ENGIE.

“The benefits have been real, both environmentally and for grid reliability. With the support of Holyoke’s citizens and HG&E, we were able to breathe new life into this retired coal plant site,” she said.

Study Examined Repurposing of Coal Plant into Energy Storage System

A report funded through a Department of Energy grant examined a scenario that called for repurposing a Duke Energy coal plant into an energy storage system by integrating the retiring asset with a Malta long duration Pumped Heat Energy Storage system (PHES).

“The project validated the technoeconomic benefits of repurposing retiring coal plants into long-duration energy storage using Malta’s PHES,” the report said.

From a technical standpoint, key findings detailed in the report were as follows:

Key findings from an economic standpoint are:

Indiana Project Calls for Battery Storage at Coal Generation Site

In July 2023, AES Indiana filed a petition with Indiana utility regulators for the operation and development of an energy storage project on the existing Petersburg Generating Station property already owned by AES Indiana.

The Pike County Energy Storage project is a standalone project composed of two sets of 100 MW/4-hour (total expected output 800 MWh at 80% of discharge level) that will be connected to two 34.5/345 kV transformers included in a single collector substation.

Batteries will be distributed via independent enclosures that feed separate inverters that interconnect on medium voltage level (34.5 kV).

The project will be located on a 26-acre footprint and is expected to be eligible for 40% Investment Tax Credit because it is located in an “energy community” as defined in the Inflation Reduction Act.

The commercial operation date is expected by December 1, 2024.

Form Energy Partners with Xcel Energy on Energy Storage Projects

Form Energy, Inc. in January 2023 announced that it had entered into definitive agreements with Xcel Energy to deploy its iron-air battery systems at two of Xcel Energy’s retiring coal plant sites.

“The storage technology will allow Xcel Energy to integrate more low-cost, renewable energy into its system and maintain reliability as it retires the coal plants in the coming years and transitions to a highly renewable future,” a news release said.

Xcel Energy–Minnesota will deploy a 10 MW/1,000 MWh multi-day storage system at the Sherburne County Generating Station in Becker, Minnesota. On July 6, the Minnesota Public Utilities Commission approved the energy storage pilot at Xcel Energy’s site in Becker, Minn.

Xcel Energy–Colorado will deploy a 10 MW /1,000 MWh multi-day storage system at the Comanche Generating Station in Pueblo, Colorado.

Both projects are expected to come online as early as 2025 and are subject to regulatory approvals in their respective states.

More recently, Xcel Energy in July 2023 issued a request for proposals for clean energy projects located in Wisconsin with commercial operation dates from 2027 to 2029. The projects will help to replace the capacity of the Allen S. King plant, a coal-fired plant in Oak Park Heights, Minnesota that is scheduled to retire in 2028.

Xcel Energy plans to reuse existing grid connections at the King plant site.

“We’ve proposed to retire all coal operations company-wide by the end of 2030,” Theo Keith, a spokesperson for Xcel Energy, told Public Power Current.

“Investing in solar and storage projects at retiring coal plant sites has multiple advantages. First, reusing existing infrastructure and grid interconnection rights allows us to provide power to customers in the most efficient and cost-effective way. Second, these projects allow us to bring new investments to communities where we’ve lived and worked for decades,” he said.

Company Proposes Energy Storage at Former Coal Plant Site in New York

Meanwhile, at a Town Board Meeting in Lansing, N.Y., in July, Ben Broder, Director of Development and Policy Strategy at Colorado-based Bear Peak Power, made a presentation about a proposal that would place a battery energy storage system at the site of the Cayuga Power Plant, a shuttered coal-fired plant.

“This particular project is very exciting because we’re able to put to use an existing interconnection and substation that was used formerly by the Cayuga coal plant,” he said at the meeting.

Broder said that the project would be a 200-megawatt, four-hour duration battery energy storage system. “The footprint of the entire project is only 5.7 acres,” he said.  Bear Peak Power has entered into a lease option with the Cayuga Operating Company for the purpose of developing and building the storage system.

In terms of the project’s timeline, Broder said it is expected to be completed in the second quarter of 2026.

Coal Plant Site in New Jersey to Host Energy Storage System

In neighboring New Jersey, the Logan Generating Plant, one of New Jersey’s last coal plants to retire, was demolished in late 2022.

At the demolition, Starwood Energy, owner of the plant, announced plans to build grid-scale battery storage on the site and use existing interconnection rights from the old coal plant to connect new offshore wind transmission lines.

Storage Project Would Located at Former Coal Plant Site in Nevada

In late June, the Town Advisory Board for Moapa, Nev., approved a plan presented by investor-owned NV Energy that calls for the installation of a battery storage system at the site of the Reid Gardner Power Station, a now-shuttered coal-fired power plant near Moapa.

In a presentation at the June 27 Moapa Town Advisory Board meeting, Mark Sullivan, a Senior Land Use Consultant with NV Energy, said that the 220-MW lithium-ion project is designed for peak time hours.

In May of this year, the Nevada Public Utilities Commission issued an order related to NV Energy’s integrated resource plan in which it said it was unable to approve the utility’s proposal for a 200-MW grid tied battery energy storage system to be located at the Valmy coal-fired power plant site in Nevada.

Specifically, the PUC said that it was “premature and unreasonable” to approve the $466 million battery energy storage system investment at Valmy as a cost-effective replacement for the coal plant “without all the necessary facts.”

The Commission said that the retirement of the Valmy plant by the previously approved date of 2025 is a significant priority for the PUC.

It directed the utility to provide additional details about the retirement of the plant including “a complete solution” for the plant’s retirement.

In July 2023, the utility outlined a plan to convert the existing coal-fueled plant at the North Valmy Generating Station – the lone coal plant in NV Energy’s portfolio – to a natural gas-fueled plant.

The North Valmy Generating Station – located in northern Nevada near Battle Mountain – “is a critical generating plant that is necessary to provide reliable power for northern Nevada customers. Refueling the North Valmy Generating Station with natural gas allows NV Energy to reduce carbon emissions by almost 50% through the elimination of coal while ensuring the company has a facility in that part of the state that can operate around the clock to meet the energy needs of our customers,” NV Energy said.

Program Offers Incentives to Install Storage Facilities at Former Coal Plant Sites

In June 2022, Illinois Gov. JB Pritzker and the Illinois Department of Commerce and Economic Opportunity announced the participants of the Coal-to-Solar Energy Storage Grant Program.

As part of the program, five coal plant sites — which are already closed or in the process of closing — were selected to participate. The program provides incentives for companies to install energy storage facilities at the sites of former coal plants.

Guided by criteria outlined in CEJA legislation, the five coal plant sites will receive a total of $280.5 million over a ten-year period (capped at $28.05 million per year), with the first payments issued in 2025 when the facilities are expected to be commercially operational. The amount of funding received by each project corresponds to the megawatts of stored energy capacity at the facilities.

The plants were selected through a competitive review process which permitted up to five plant sites to be selected.

In order to qualify, the plants must have burned coal, have a generating capacity of at least 150 MW of electricity, and make a commitment to hiring a diverse workforce and apprentices.

The program provides $110,000 per megawatt of stored solar energy (with a yearly cap of $28.05 million for all recipients) and each project must have a storage capacity of a minimum of 37 MW.

In 2021, the Illinois General Assembly passed SB 2408, the Energy Transition Act, an omnibus energy package that cleared a path for Vistra Corp. to build and operate up to 300 MW of utility-scale solar and 150 MW of battery energy storage facilities at nine retired or to-be-retired coal plant sites across central and southern Illinois.

Hawaii 185-MW Storage Project Would be Located at Former Coal Plant Site

In Hawaii, an energy storage project being developed by Plus Power will be located on roughly eight acres of land in Kapolei on the island of Oahu, where it will interconnect at a Hawaiian Electric substation.

The 185-MW/ 565 MWh battery storage project will provide load shifting and fast-frequency response services to Hawaiian Electric, enhancing grid reliability and accelerating the integration of readily available renewable energy.

The project received approval from the Hawaii Public Utilities Commission in May 2021.

The project will help replace an AES coal-fired plant that closed on September 1, 2022, supporting the state’s goal of shifting from fossil fuels to 100 percent renewable energy generation, Plus Power said.

Trend is Also Seen in Other Countries

The trend of siting energy storage facilities at coal plant sites is not limited to the U.S., with several other countries seeing the emergence of similar plans.

In August 2023, SSE Renewables started construction on a 150MW/300MWh battery energy storage system at Ferrybridge, West Yorkshire, U.K., with a groundbreaking ceremony. A coal-fired plant was located at the site until its decommissioning by SSE in 2016.

In Australia, ENGIE and its partners Eku Energy and Fluence in June of this year announced the commissioning of the Hazelwood Battery Energy Storage System, a utility-scale battery of 150 MW/150 MWh, located on the site of the former Hazelwood coal-fired power plant.

Meanwhile, ESS Tech Inc., a manufacturer of long-duration energy storage systems, and LEAG, a major German energy provider, in June 2023 signed an initial agreement to deploy renewable generation and long-duration energy storage using ESS iron flow battery technology.  

LEAG and ESS plan to build a 50 MW/500 MWh iron flow battery system at the Boxberg coal-fired power plant site in Germany, to be commissioned in 2027.

OMPA Board Approves Agreement with Virtual Peaker

September 11, 2023

by Paul Ciampoli
APPA News Director
September 11, 2023

The Board of Directors for the Oklahoma Municipal Power Authority this summer approved an agreement with Virtual Peaker that will allow customers of OMPA members to be able to enroll in a demand response program.

Virtual Peaker is a software-based company designed to manage distributed energy resource programs for electric utilities.

“OMPA intends to work with Virtual Peaker to administer a demand response program that will help the Authority manage peak loads while offering incentives to customers who participate,” a story in OMPA’s Outlet newsletter noted.

The program would involve customers agreeing to allow their thermostat settings to be adjusted during peak events, which are typically called during the hours of 10 a.m. to 8 p.m.

Customers enrolled in the program would be notified of a peak event and then have their demand curtailed for no more than three hours. The customer can opt out of the program at any time.

Customers who participate in the program will receive a financial incentive at the time of enrollment and are then eligible for more incentives after following through on participation.

Smart thermostats eligible for the program include those manufactured by Google Nest, Honeywell, Emerson, Sensi and Ecobee Wi-Fi.

OMPA is a wholesale power entity owned by 42 municipal electric utilities located in 29 Oklahoma counties.

Inflation Reduction Act Increasing Demand for Minerals Critical to Energy Transition

September 7, 2023

by Peter Maloney
APPA News
September 7, 2023

The Inflation Reduction Act is accelerating demand for critical minerals and copper needed for the energy transition, according to analysis by S&P Global.

Energy transition-related demand for lithium, nickel and cobalt will be 23 times higher in 2035 than it was in 2021 and demand for copper will be twice as high, the study found.

The study, Inflation Reduction Act: Impact on North America Metals and Minerals Market, sees “considerable challenges” in meeting the increased demand driven by the Inflation Reduction Act for decarbonization technologies such as electric vehicles, charging infrastructure, solar photovoltaics, wind turbines, and lithium ion batteries.

The study says demand will continue “to accelerate and be materially higher” for lithium, cobalt, and nickel with demand rising 15, 14 and 13 percent, respectively, by 2035 compared with projected increases before the Inflation Reduction Act was enacted in August 2022.

Demand for copper will be 12 percent higher by 2035 than pre-Inflation Reduction Act projections, the study found. Copper is not currently listed as a critical mineral in the United States and does not qualify for Inflation Reduction Act tax credits, but its role as the “metal of electrification” makes it vital to the energy transition and demand for it will rise as it is used alongside critical minerals in energy transition applications, the study said.

To qualify for Inflation Reduction Act tax credits, processing and/or extraction of critical minerals used must be in the United States and/ or in a country with which the United States has a free trade agreement and that sourcing cannot involve a “foreign entity of concern.”

Of the four materials analyzed in the study, only lithium is likely to be sufficiently supplied to the United States under the Inflation Reduction Act’s domestic content requirements while cobalt and nickel are both unlikely to be sourced at levels high enough to meet demand, the study found.

Countries with which the United States has free trade agreements already produce enough cobalt to meet the Inflation Reduction Act domestic sourcing requirement, but the United States does not currently source most of its cobalt from those countries and doing so would require a reorientation of trading patterns across several countries given intense international competition for resources, the study said.

Nickel is the most challenged in terms of supply, and there does not appear to be enough supply in countries with which the United States has free trade agreements to meet demand under the Inflation Reduction Act requirements, even if those countries exported all their production to the United States, the study said.

Even though copper is not subject to sourcing requirements under the Inflation Reduction Act, ensuring access to enough supply to meet U.S. post-Inflation Reduction Act demand is also at risk, the study found. The United States is likely to become more reliant on imports as growing demand for energy transition related end markets outpaces domestic supply, the study said.

In addition, S&P Global data on 127 mines across the world that began production between 2002 and 2023 shows that a major new resource discovery today would not become a productive mine until 2040 or later, the study said.

Google Signs PPA for 189-Megawatt North Carolina Wind Farm

September 7, 2023

by Peter Maloney
APPA News
September 7, 2023

Apex Clean Energy and Google recently announced a power purchase agreement for the full 189-megawatt capacity of Timbermill Wind that Apex is building in North Carolina.

Apex said the power purchase agreement will contribute to the clean energy needs of Google’s data centers on PJM Interconnection’s grid.

The planned wind farm is expected to consist of up to 45 wind turbines installed in managed timberland and open farmland in rural Chowan County. The turbines would be spaced about one-quarter to on-half a mile apart, and each would require about half an acre of land.

Existing high-voltage power lines and highways would limit the need for new infrastructure, Charlottesville, Virginia-based Apex said, adding that landowners in the area would be able to continue to farm their land or harvest timber with limited disturbance.

The Timbermill Wind project has received all necessary permits from local, state, and federal jurisdictions and is moving forward with construction, Apex said. The company began construction work began in May and expects turbine deliveries in 2024 and full commercial operation in 2024-2025.

The Timbermill Wind would be the second utility scale wind farm in service in North Carolina.

The state’s first wind farm, the 208-MW Amazon Wind Farm US East, is operated by Avangrid Renewables in Pasquotank and Perquimans counties and entered service in 2017.

The power generated by the wind farm is delivered under a contract with Amazon Web Services into the electrical grid that supplies both current and future Amazon Web Services cloud data centers.

NRC Accepts for Review Application Related to UAMPS Small Modular Reactor Project

September 7, 2023

by Paul Ciampoli
APPA News Director
September 7, 2023

The U.S. Nuclear Regulatory Commission has accepted a Limited Work Authorization application for formal review related to a small modular reactor project being pursued by Utah Associated Municipal Power Systems.

After technical review of the application, which was submitted on July 31, 2023, the NRC has docketed the application that seeks approval to commence early construction activities for the Carbon Free Power Project prior to issuance of the Combined License.

The NRC staff’s goal is to conduct and complete an efficient and high-quality review of the LWA application by August 2025, which will align with scheduled activity progression on the project.

When approved, the LWA will pave the way for the initiation of early-scope construction that is expected to start mid-2025.

“Our team is pleased that the NRC has accepted the LWA application as it represents a major achievement in the project’s advancement and brings the CFPP closer to its objective,” said Mason Baker, CFPP LLC President. CFPP LLC is a wholly-owned subsidiary of UAMPS.

“The commencement of early construction activities is a vital step in advancing the project and sets a noteworthy precedent in the field of small modular nuclear energy regulation and development,” he said.

CFPP LLC submitted the LWA application as the first part of the CFPP Combined License Application.

This was the first instance under the current LWA regulations where a standalone LWA application was submitted in advance of the remainder of the COLA. The second part of the CFPP Combined License Application remains on schedule to be submitted to the NRC in January 2024.

The LWA application acceptance is a key development for the CFPP.

The CFPP will utilize NuScale Power’s VOYGR™-6 SMR power plant design. NuScale’s Standard Design Approval application is based on a VOYGR power plant design featuring six 77 MWe NuScale Power Modules™.

The CFPP is proposed to be sited within the southwest region of the Idaho National Laboratory in southeast Idaho. The INL site, a U.S. Department of Energy facility, covers an expansive area of approximately 890 square miles and is situated near Idaho Falls, Idaho.

Kansas Municipal Energy Agency Helps City Expand Substation

September 7, 2023

by Paul Ciampoli
APPA News Director
September 7, 2023

The Kansas Municipal Energy Agency is helping the City of Lindsborg, Kansas, to expand the city’s existing substation with the addition of the second transformer. 

KMEA reported the news in its most recent Utility Connection newsletter.

In 2022 the City of Lindsborg’s city council authorized the purchase of the current transformer at the substation from Evergy and add a new 10 MVA transformer.   

The goal for this project was to control redundancy and reliability for the city as the current transformer ages, KMEA noted.

“A key factor in the decision to purchase the old transformer was the peak load on the old transformer was reaching the limit of their 7/10 MVA transformer which serves the city,” KMEA said in the newsletter.

The 10 MVA transformer was installed at the substation on August 18 with operation date expected later this fall. 

By adding the second transformer, the city will have the ability to split the load between the two transformers, KMEA noted. It will also allow for maintenance on either transformer without having to take an outage or bring in temporary substations or generation.

Memphis Light, Gas and Water Planning for Up to 100-MW of Battery Storage

September 7, 2023

by Paul Ciampoli
APPA News Director
September 7, 2023

Memphis Light, Gas and Water on Aug. 23 said that it has started the planning necessary to deliver utility scale battery storage of up to 100 megawatts into the local electric distribution system.

 Once installed, these batteries will hold enough electricity to power the equivalent of 100,000 homes for four hours, the Tennessee public power utility noted.

“This effort will help MLGW provide additional resilience in the face of increasing energy demand and will help achieve community goals by reducing reliance on conventional power plants to meet peak electricity demands,” it said.

Additionally, in its effort to meet the need for clean, affordable energy in 2024 MLGW will determine the feasibility and initial specifications for the first MLGW owned, utility scale, solar generation facilities, consistent with the current Tennessee Valley Authority power supply agreement.

Meanwhile, MLGW CEO Doug McGowen last month appeared at a TVA Board listening session lending his support for the transition of outdated equipment to a newer, more efficient, state of the art system, MLGW noted in a news release.

Public Power Utilities Help Cooperatives with Power Restoration Efforts in Florida

September 6, 2023

by Paul Ciampoli
APPA News Director
September 6, 2023

Public power utility crews have been helping electric cooperatives in Florida restore power in the wake of Hurricane Idalia, which hit the state in late August. 

“Florida public power is incredibly grateful for the more than 360 personnel from 58 utilities in Florida and from 13 other states including Alabama, Louisiana, Ohio, Michigan, Kentucky, Oklahoma, Nebraska, Texas, Missouri, Arkansas, Georgia, Tennessee, and Iowa, along with hundreds of contractors and tree crews, that worked around the clock to restore power to more than 99.99% of public power customers within 48 hours of Hurricane Idalia making landfall,” said Amy Zubaly, Executive Director of the Florida Municipal Electric Association.

“After getting the lights back on in our own communities, public power again answered the call to help neighboring communities that are continuing to recover from the storm,” she said.

“While some of our mutual aid crews were released back to their hometowns, FMEA was happy to be able to redeploy some of our mutual aid crews, along with our own public power crews to assist other utilities as they restore power for communities in need,” Zubaly noted.

“We greatly appreciate the hard work of our lineworkers and all the mutual aid crews who spent long hours in the heat and humidity to get power flowing back to customers as quickly as they could and continue to do so for other utilities in need,” she said.

FMEA on Sept, 6 provided an overview of how public power utilities have assisted cooperatives with restoration efforts.

After initially deploying to help Florida public power utilities, crews from Riviera Utilities, the City of Fairhope and City of Troy Utilities — all from Alabama – joined crews from Florida public power utility Gainesville Regional Utilities and the public power communities of the City of Newberry and City of Starke to help restore power to Central Florida Electric Cooperative, headquartered in Chiefland.

Since then, Central Florida Electric Cooperative has restored power and the original contingent of three Alabama and three Florida crews have been redeployed. Most all of those listed above — both the Florida and Alabama crews (with the exception of Fairhope) — were reassigned to Suwannee Valley Electric Cooperative, based in Live Oak, Fla.

Meanwhile, the City of Fairhope, Ala., joined the City of Andalusia, Ala., to help Tri-County Electric Cooperative, based in Madison, Fla. Andalusia was already assisting TCEC after being released from Green Cove Springs, Fla., on day one.

In addition, AMP (Orville, Cuyahoga Falls, Westerville, Bowling Green, Wapokoneta, Bryan, Lebanon, Wadsworth and Piqua – all Ohio public power communities – and Wyandotte, MI); Paducah and Owensboro, KY; Lincoln Electric System, Grand Island, and OPPD, NE; Grand River Dam, Skiatook, and Edmond, OK; were all assigned to Suwannee Valley Electric Cooperative as well after being released from Tallahassee, Fla.

Also after being released from Tallahassee, Louisiana public power utility Lafayette Utilities System, Florida public power utilities Orlando Utilities Commission, Lakeland Electric, and the Kissimmee Utility Authority joined Tallahassee crews and were all deployed to help Tri-County Electric Cooperative.

More than 300 public power personnel were helping Tri-County Electric Cooperative and Suwannee Valley Electric Cooperative — the two hardest hit utilities, FMEA reported on Sept.6.

And after Florida-based public power utility JEA in Jacksonville restored power to its customers, their crews traveled to Georgia to help investor-owned Georgia Power with its restoration efforts.

DOE to Fund Research to Reduce Costs of High-Voltage Direct Current Transmission

September 6, 2023

by Paul Ciampoli
APPA News Director
September 6, 2023

The U.S. Department of Energy’s Wind Energy Technologies Office and Office of Electricity plan to fund research to reduce costs of high-voltage direct current voltage source converter transmission systems, DOE reported in late August.

DOE noted that HVDC transmission systems are more efficient than traditional alternating current transmission systems for transmitting electricity over long distances while minimizing power losses.

Many renewable resources are in remote locations on land, or planned far from shore (e.g. offshore wind), “and HVDC transmission provides a cost-effective solution for renewable integration onto the grid,” it said in unveiling the plan to fund future research.

HVDC transmission requires converters to switch the power from AC to DC and back again to connect to the grid. The optimum converter configuration is the voltage source converter as it can turn itself on and off via control commands unlike other types of HVDC converters, according to DOE.

“This investment is intended to enable future grid upgrades that will be needed to cost-effectively integrate an increasing amount of renewable energy generation on to the grid, both onshore and offshore,” the federal agency said.

It is also the first action taken to support DOE’s HVDC COst REduction (CORE) Initiative, which aims to reduce the cost of HVDC systems by 35% by 2035 to promote widespread adoption of the technology.

Cost-effective HVDC VSC transmission systems will enable and simplify interconnection of renewable resources onto the nation’s grid, it said.

This future funding opportunity announcement is expected to seek applications for innovative designs of HVDC voltage source converter systems to reduce costs and promote adoption of the technology across the United States.

Target areas for innovation under this future FOA may include increasing the power capacity of the converter, decreasing the size of the converter substation, and increasing the lifespan of the system.  

The FOA is expected to be released between late September and late November 2023.

APPA Weighs in On EPA Proposed Rule to Amend Engine Requirements

September 5, 2023

by Paul Ciampoli
APPA News Director
September 5, 2023

The American Public Power Association submitted comments on August 25 in response to the Environmental Protection Agency proposed National Emission Standards for Hazardous Air Pollutants: Reciprocating Internal Combustion Engines and New Source Performance Standards: Internal Combustion Engines; Electronic Reporting rule.  

APPA’s comments in response to the Proposed Rule addressed arguments by opponents related to the “100-hour provision” in the 2013 RICE NSPS and NESHAP rules, which was vacated in Delaware v. EPA (2015).

The related challenges in that case to the “50-hour provision,” which, pursuant to the agency’s motion, were severed from the Delaware v. EPA case and continue to be held in abeyance pending the agency’s reconsideration of that provision.

The current 50-hour non-emergency provision has been utilized by APPA’s members sparingly to address local reliability concerns such as voltage sags, transmission line maintenance, and non-emergencies such as ramping-up operations of steam generation equipment during black start conditions following an emergency. Also, some of APPA’s members have entered into financial agreements to dispatch the engines under the 50-hour provision.

Background

APPA, in its comments, noted that it has long advocated for EPA to allow limited hours of usage under the RICE rules for electric utilities to call on “emergency engines” on a limited basis to address “non-emergency uses” to stabilize and protect local electricity transmission areas.  In its comments, APPA refers to these RICE as “emergency engines” to distinguish them from RICE at members’ facilities that are compliant with the RICE regulations.

“Many of APPA’s members own such engines, which are not cost-effective to retrofit but are maintained and tested, consistent with the RICE regulations so that they can be operated reliably as emergency engines for brief periods for emergency or non-emergency purposes pursuant to the RICE regulations,” APPA noted.

APPA members also, from time to time, have entered into financial arrangements to dispatch RICE units in non-emergency situations with other generation operators in “balancing areas” and/or with independent system operators and regional transmission organizations.

In past discussions with EPA staff and in briefs in defense of the use of the emergency engines in the Delaware case — which APPA participated as an Intervenor Respondent on EPA’s behalf- — APPA emphasized that rural communities, including municipally-owned power plants and rural cooperatives that are literally “at the end of the transmission line,” have been more susceptible to voltage sags and other local electricity outages that jeopardize their local service areas.

APPA Urges Retention of 50-Hour Provisions in RICE Rule

Removal of the 50-hour provisions from the current RICE rule “could harm public power communities because municipally owned and operated power generators will no longer be able to call on these onsite engines to help stabilize and protect the local transmission system or to maintain water pressure to operate fire pumps and safety lighting,” APPA argued.

“To the extent that some of the Association’s members, all of which are not-for-profit entities, enter agreements with balancing authorities or other entities for demand response, the recission of the rules also will eliminate a modest funding source that cities use for maintenance and testing of these emergency engines and fuel for the engines,” it said.

EPA sought comment on whether there are potential revisions that would narrow the 50-hour provision “to ensure that its use is limited to remote rural areas (if those are the only areas where it is needed).”

APPA does not believe the non-emergency provision should be limited to “remote rural areas.”

“Now, and over the next decade, APPA believes that the importance of the 50-hour RICE provisions may grow in both rural and urban areas, given the increase in non-dispatchable generation (e.g., intermittent energy sources like solar and wind-generated power) and load growth,” it said.

In addition, emergency engines are also a viable means for addressing unprecedented weather conditions and other events across the country, APPA said.

Extreme weather events have not been confined to Texas and California and include areas in Kansas served by KPP Energy, it noted.

In 2021 and 2022, the Southwest Power Pool region experienced widespread failure in the natural gas markets. Intermittent generation was not available, and natural gas dispatchable resources were limited due to natural gas availability. “While the events in 2021 and 2022 were short in duration, even the smallest generator was critical to prevent local voltage collapse and cascading outages,” APPA said.

“Public power, like other power systems, address the impending loss of transmission by dropping load, alerting resident to discontinue the use of unnecessary appliances, etc. The ability to operate emergency engines under the 50-hour provision during these events can provide a valuable, if very limited, transition tool to ‘lower generation’ safely or to bring up engines from black start conditions, and thus protect employees and generation resources, the surrounding community, and the environment.”

EPA also asked for comment on whether it should delete the provision rather than attempting to narrow it or make other changes to it.

“Our members are adamant that the regulation should not be deleted. As the power sector transitions to lower and non-emitting generation resources, public power utilities are balancing the system with all available resources, including the potential to operate emergency engines,” APPA said.

The trade group also said that the proposed rule appears to seek responses to the arguments that challengers made in Delaware v. EPA, to the 100-hour demand response provisions in the RICE rules.

These challenges were not specifically adjudicated by the court in the Delaware case because the D.C. Circuit held that the 2013 RICE NESHAP 100-hour provisions for the operation of emergency standby engines for the national grid were arbitrary and capricious.

EPA also requested comments related to criticisms of the 50-hour non-emergency provision made in the Conservation Law Foundation’s brief, which was filed in the Delaware case before CLF’s challenge to the 50-hour provision was severed from the case, and the 50-hour provision was remanded to the EPA for further consideration.

Petitioners and supporting Intervenors-Petitioners argued that demand response in capacity markets based on the use of emergency generators have, had, or will have negative effects on the overall reliability of the national electrical grid for a number of reasons.

APPA argued that retaining the 50-hour non-emergency allowance “did not and will not affect the reliability of the U.S. electric markets, nor did it or will it incentivize operators or ‘energy brokers’ to bundle and attempt to dispatch old engines, forcing out more efficient and/or cleaner generation.”

In APPA’s experience over the last decade, the use of emergency engines under the 50-hour provision has not made the transmission of electricity more vulnerable, it noted.

“The use of emergency engines is not viable to meet the nation’s demand for electricity and has not replaced the energy supply from conventional electric generating units. These emergency engines are not as efficient as regulated RICE, and they are not as economical to operate, even for short time intervals, except for non-emergency and emergency events when there is no other EGU available.”

Nor does the Association “believe that there is any evidence that any local or regional operator has ever suggested the use of these emergency engines is a solution or potential solution to current national energy transmission problems, which are generally attributed to insufficient transmission infrastructure and increased energy demand around the country.”

The majority of the emergency engines that would be allowed to run under the 50-hour provisions were built decades ago and are not nearly as efficient as modern RICE-compliant internal combustion engine generators based on fuel input and energy output, it added.

Electronic Reporting Provisions

The proposed rule also seeks to add electronic reporting provisions to simplify reporting by affected sources and to make the data more readily accessible.

APPA said that provisions for reporting the dispatch of emergency engines need to be clarified to prevent confusion, particularly in the situation where the engine is dispatched by a balancing authority or transmission or dispatch operator.