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Rhode Island Utility Seeks Up to 1,000 MW of Offshore Wind Capacity

October 18, 2022

by Paul Ciampoli
APPA News Director
October 18, 2022

Rhode Island Gov. Dan McKee on Oct. 14 announced a request for proposals has been released by Rhode Island Energy for up to 1,000 megawatts of new offshore wind capacity.

In July, McKee signed into law legislation that seeks to expand Rhode Island’s offshore wind energy resources. The new law requires a market-competitive procurement for between 600 and 1,000 megawatts of newly developed offshore wind capacity. 

This offshore wind procurement will have the potential to meet at least 30 percent of Rhode Island’s estimated 2030 electricity demand.

When added to the 30-megawatt Block Island Offshore Wind Farm and the planned 400-megawatt Revolution Offshore Wind project, about half of the state’s project energy needs will be powered by offshore wind.

The offshore wind procurement RFP will be posted at the following website: https://ricleanenergyrfp.com/. 

Offshore wind project proposals by bidders will be due to Rhode Island Energy on February 1, 2023.

Recent California Energy Storage Battery Fire Draws Renewed Attention to Storage Safety Issues

October 17, 2022

by Paul Ciampoli
APPA News Director
October 17, 2022

A recent fire at a battery storage facility in California is bringing fresh attention to safety issues tied to energy storage as the technology grows in deployment across the U.S.

The fire occurred in September 2022 at Pacific Gas & Electric’s (PG&E) Moss Landing battery storage facility in California. The fire was isolated to a single battery pack at the facility, according to the County of Monterey, Calif.

PG&E in April announced the commissioning of its 182.5-megawatt (MW) Tesla Megapack battery energy storage system – known as the Elkhorn Battery – located at its Moss Landing electric substation in Monterey County.

The Elkhorn Battery system was designed, constructed, and is maintained by both PG&E and Tesla, and is owned and operated by PG&E.

An editorial in California’s Santa Cruz Sentinel newspaper said that while the move to energy storage will continue, the Moss Landing fire “was also a reminder that battery blazes are becoming increasingly common and destructive – and safety measures, including fire drills, for residents around storage facilities will have to be put in place and widely disseminated.”

Arizona Also Experiences Incidents With Storage Fires

California is not the only state where energy storage facilities have experienced fires.

In neighboring Arizona, investor-owned Arizona Public Service (APS) in 2020 released the findings of an investigation into an incident that occurred at an APS battery storage site in 2019.

Around 5 p.m. on April 19, 2019, there were reports of smoke from the building housing the energy storage system at APS’s McMicken site in Surprise, Ariz.

Hazardous Material units and first responders arrived on scene to secure the area. Approximately three hours after the reports of smoke and shortly after the door was opened, the site experienced a catastrophic failure. Injured first responders were transported to area hospitals.

An investigation led by APS, with first-responder representatives, the system integrator, manufacturers and third-party engineering and safety experts, was conducted to determine the cause of the incident and identify lessons that can be applied to future battery energy storage systems.

The investigation involved a number of key stakeholders, and APS commissioned several forensic experts and nationally recognized research institutions. Once the investigative work was completed, APS chose DNV GL to combine various forensic and expert inputs into the single, consolidated report.

Among other things, the report said that the suspected fire “was actually an extensive cascading thermal runaway event, initiated by an internal cell failure within one battery cell in the BESS [battery energy storage system].”

In August 2019, an Arizona utility regulator raised questions about the safety of certain lithium-ion batteries, following fires at APS battery storage facilities.

In a letter to her fellow commissioners, commission staff and other interested parties, Commissioner Sandra Kennedy, of the Arizona Corporation Commission, said the types of lithium ion chemistries used at those facilities “are not prudent and create unacceptable risks.”

Along with the April 19 fire, Kennedy’s letter also cited a November 2012 fire at an APS storage facility at its Elden substation.

More recently, a fire broke out an energy storage facility in Chandler, Ariz., in April 2022. The incident occurred at the Dorman battery storage system, a 10 MW, 40 megawatt-hour stand-alone battery storage system in Chandler. The BESS is interconnected with and provides service to the Salt River Project. It is owned by AES Corp.

The investigation “into what happened at Chandler is still underway. We expect a determination in the coming weeks,” said AES spokesperson Gail Chalef on Sept. 26.

Standards for Energy Storage Systems

A key player in addressing concerns about energy storage technology safety issues is the National Fire Protection Association (NFPA).

“NFPA is keeping pace with the surge in energy storage and solar technology by undertaking initiatives including training, standards development, and research so that various stakeholders can safely embrace renewable energy sources and respond if potential new hazards arise,” it notes on its website.

NFPA’s safety standard, NFPA 855, “provides insight into mitigating risks and helping to ensure all installations are performed appropriately, taking into account vital life safety considerations,” NFPA states. The standard “offers comprehensive criteria for the fire protection of ESS installations based on the technology used in ESS, the setting where the technology is being installed, the size and separation of ESS installations, and the fire suppression and control systems in place.”

And cities are proactively taking steps to address storage-related safety issues. The New York City Fire Department in 2019 adopted a final rule related to energy storage systems.

The Fire Department adopted the rule to establish standards, requirements and procedures for the design, installation, operation and maintenance of outdoor stationary storage battery systems that use various types of new energy storage technologies, including lithium-ion, flow, nickel-cadmium and nickel metal hydride batteries. The rule does not govern indoor battery installations.

Among other things, the rule sought to address fire safety concerns associated with new battery technologies by setting testing standards and establishing an equipment approval process for manufacturers.

“Establishing testing standards, and in particular, requiring full-scale testing of battery system components and pre-engineered products, will enable manufacturers to identify fire safety issues and eliminate them or engineer mitigating measures in the design,” the Fire Department said. “The evaluation of the performance of battery system components or products in this manner will also allow the Fire Department to eliminate or expedite its approval process for specific installations,” it said.

Virginia County Holds Off on Battery Storage Project Decision

Concerns over battery storage fires and safety prompted the James City County Board of Supervisors in Virginia to recently defer a decision on a proposed battery storage facility in the county.

At issue is a 22.35-MW lithium ion battery storage project proposed by Calvert Energy LLC.

At the Oct. 11, 2022 board meeting, several members of the James City County Board of Supervisors raised questions related to fire and safety issues involving the project.

Brian Quinlan, President and CEO of Calvert Energy, noted the NFPA standard for batteries “and this system is designed to meet or exceed the containment requirements for battery storage, which basically means that the fire is contained within the container, so it won’t burn through the container walls.”

The Calvert Energy project also includes blowout panels, he noted. This means that “gases won’t build up and cause an explosion.” In addition, there is also dry chemical fire prevention “built into the unit itself as well, so there’s a number of different levels of fire protection built into the system.”

The board voted to defer a decision on the project to its Nov. 8 meeting.

RFQ in Massachusetts Addresses Storage Fire Training

The City of Boston in late 2021 issued a request for qualifications (RFQ) to provide comprehensive engineering, design, and construction services in connection with the installation of a rooftop photovoltaic (PV) array, a commercial-scale battery energy storage system (BESS) and a residential-scale battery energy storage system at the Boston Fire Department’s Fire Training Academy on Moon Island, in Quincy, Mass.

The RFQ said that at a minimum the BESS “shall meet and fully satisfy the Standard for the Installation of Stationary Energy Storage Systems established by the National Fire Protection Association (NFPA 855), including any underlying standard adopted by and incorporated into NFPA 855, such as UL 9540A.”

The RFQ notes that the project is intended to complement the Boston Fire Department’s curriculum for firefighting trainees: in particular, to provide those trainees with an opportunity to become familiar with working examples of PV and BESS technologies.  

Joseph LaRusso, Energy Efficiency and Distributed Resources Finance Manager in the City of Boston’s Environment Department, told Public Power Current that the city has completed evaluating the qualifications statements that were submitted in response to the RFQ, and the city is currently negotiating the terms of an energy services agreement (ESA) with the firm that submitted the highest-ranked proposal.

The city plans to release the name of that company once the terms of the ESA have been successfully negotiated and the contract is awarded.

APPA Responds to FERC’s Generator Interconnection Reform Proposal

October 17, 2022

by Paul Ciampoli
APPA News Director
October 17, 2022

The Federal Energy Regulatory Commission (FERC) should consider a number of modifications and/or clarifications to a generator interconnection Notice of Proposed Rulemaking (NOPR) to help ensure that any final rule improves interconnection queue processing while not inadvertently creating problems that could impose unnecessary costs and inefficiencies on transmission providers, interconnecting generators, and existing transmission customers, the American Public Power Association (APPA) and the Large Public Power Council (LPPC) said.

The Oct. 13 comments filed by APPA and LPPC came in response to a NOPR issued by FERC in June 2022. In the NOPR, FERC proposed to reform its generator interconnection procedures and pro forma interconnection agreements to address interconnection queue backlogs.

Although the proposals in the NOPR are not directly applicable to public power transmission owners, public power utilities in regional transmission organization (RTO)/independent system operator (ISO) regions may be subject to the proposed requirements under RTO/ISO tariffs or other governing agreements. 

Also, as FERC specifically states in the NOPR, transmission providers that are not utilities subject to FERC’s general transmission jurisdiction (such as public power utilities) would be required to adopt the requirements of the NOPR as a condition of maintaining the status of any safe harbor tariff to satisfy the reciprocity requirements of FERC Order No. 888. 

In their comments, APPA and LPPC note that they generally support the initiatives in the proposed rule, “and we are gratified in particular by the NOPR’s focus on improving the incentives generation developers have to stand behind bona fide interconnection applications, which should have a substantial stabilizing effect.”

A common refrain in their comments is the need for flexibility in implementing certain of the NOPR’s proposals, particularly to accommodate existing generator interconnection processes that have made progress in addressing the types of challenges cited in the NOPR.

APPA and LPPC said that FERC should not adopt the NOPR’s proposal to require transmission providers to undertake informational interconnection studies. 

“Substantial information is already made available to prospective interconnecting customers, and the informational study requirement would transfer the current burdens associated with processing speculative interconnection requests to an extra-LGIP process.”

APPA and LPPC endorsed the proposed requirement to post certain interactive information for use by prospective generator interconnection customers, though they argued that the Commission should clarify that transmission providers would not be required to conduct any individualized analyses in response to use of these interactive tools.

While APPA and LPPC support the NOPR’s proposed requirement to use a cluster study approach in studying generator interconnection requests, they said the Commission should allow for an exception where there are too few interconnection applications to justify a cluster study approach. 

In addition, the groups said that FERC should allow for flexibility in the cost allocation methods used to allocate cluster study costs and to allocate costs of required transmission system network upgrades identified in the cluster study.

APPA and LPPC said they strongly support the Commission’s proposal to adopt financial commitment and readiness reforms for prospective generator interconnection customers. They said the Commission should not dilute these reforms by allowing an interconnection customer to provide a deposit in lieu of making a showing of commercial readiness. “It may be appropriate to permit deposits in lieu of demonstrating full site control in circumstances where an interconnection customer is genuinely prohibited by regulatory limitations from obtaining site control, or where particular regions have specific reasons to adopt a deposit-in-lieu-of-site-control framework,” they said.

The NOPR’s proposal to impose stricter study processing requirements on transmission providers, backed by penalties, is generally a reasonable complement to the application of stricter financial commitment and readiness requirements on interconnection customers, APPA and LPPC said. 

“The Commission, however, should allow for flexibility in transmission provider deadlines, particularly in Regional Transmission Organization and Independent System Operator regions, particularly where the transmission provider has been permitted to utilize a cluster study approach that differs from the pro forma LGIP requirements.”

FERC should not adopt a penalty framework under which RTOs and ISOs might be obligated to pass penalties through to RTO/ISO members that bear no responsibility for interconnection study delays, they said. “The Commission should adopt a reporting requirement for RTOs and ISOs as a substitute for imposing interconnection study delay penalties on these not-for-profit entities.”

The groups also said that:

APPA and LPPC also specifically responded to the NOPR’s statement that public power utilities would be obligated “to adopt the requirements of this Proposed Rule as a condition of maintaining the status of their safe harbor tariff or otherwise satisfying the reciprocity requirement of Order No. 888.”

While acknowledging that safe harbor tariff requirements will be modified pursuant to any final rule in this case, APPA and LPPC expressed concern that the Commission’s statement failed to acknowledge that the reciprocity requirements of Order No. 888 can also be satisfied through bilateral arrangements or by waiver.  APPA and LPPC asked FERC to make clear in any final rule that public power utilities would still be able to satisfy the reciprocity requirements under Order No. 888 through bilateral arrangements and/or waiver.

Inflation Reduction Act, Retiring Coal Plants Create Opportunities for Advanced Nuclear Plants

October 16, 2022

by Peter Maloney
APPA News
October 16, 2022

The retirement of aging coal-fired plants combined with the recently passed Inflation Reduction Act has created an opportunity for public power utilities looking to secure long-term, reliable supplies of clean energy, according to advanced nuclear firm NuScale Power.

“The Inflation Reduction Act is the first transformative climate piece of legislation ever in the U.S. to treat nuclear energy as a clean energy source,” Chris Colbert, Chief Financial Officer at NuScale Power, said.

The Inflation Reduction Act of 2022 (IRA) provides production tax credits (PTC) for existing nuclear power plants but, more importantly, for new nuclear power plants and specifically for advanced reactors and small modular reactors – the type NuScale Power is working on. The IRA amends the definition of a qualified facility eligible for a “clean PTC” to mean any plant placed into service after Dec. 31, 2024, that produces zero greenhouse gas emissions.

The IRA also amends the Internal Revenue Service (IRS) rules on qualifying for a clean energy investment tax credit (ITC) by changing the language in the code to allow investments for advanced reactors to qualify for the credit. The change provides a tax credit of 30 percent of the cost of building a zero-emission advanced nuclear power plant that is placed in service after 2025.

“If you design and plan to put in a small modular reactor at the site of a retired coal plant, there is a further 10 percent ITC available, and if you use domestic content there is another 10 percent ITC added on,” Colbert said. “That can add up to a 50 percent reduction in costs.”

In September, the Department of Energy (DOE) released a study that found that hundreds of coal power plant sites across the country could be converted to nuclear power plant sites.

Of the 157 retired coal plant sites and 237 operating coal plants surveyed, the DOE study found that 80 percent were good candidates to host advanced reactors that are smaller than 1 gigawatt (GW).

Converting retired coal plant sites to nuclear power has the potential to add 64.8 GW of clean energy to the power system, and converting operating coal plant sites to nuclear power could add 198.5 GW to the grid, the DOE found.

Between 2015 and 2020, an average of 11 GW of coal-fired capacity retired every year, according to the DOE. The pace of retirements slowed in 2021, to 4.6 GW, but is expected to pick up this year with 12.6 GW of coal retirements scheduled. Additionally, plant owners and operators say they plan to retire 59 GW of the coal-fired capacity by 2035.

Each NuScale small modular reactor (SMR) is designed to generate 77 megawatts (MW) of electricity. Up to 12 SMRs can be combined to make a 924-MW VOYGR™-12 power plant. In addition to their compact design, which makes them scalable and cost competitive, SMRs have enhanced safety features. NuScale’s Power Modules are designed to safely shut down and self cool indefinitely without the need for an external power source. And the factory-fabricated design of a NuScale SMR allows them to be built and assembled in the United States.

Converting the site of a coal plant to nuclear power could also increase employment and economic activity in affected communities, according to the DOE report. And replacing a large coal plant with a nuclear power plant of equivalent size could increase jobs in the region by more than 650 permanent positions, leading to additional annual economic activity of $275 million, implying a 92 percent increase in local tax revenue compared with the tax revenues from the operating coal power, the DOE study found. A case study included in the report was based on a NuScale design example.

For public power utilities, the employment and tax concerns could be a particularly important consideration when deciding what to do with a coal plant or how to meet growing electricity demand while pursuing goals to move toward a clean energy or zero emissions economy.

“The question is, what are you replacing it with,” Colbert said. “By converting to nuclear power, you can do it in a way that does not throw hundreds of people out of work. Those workers would basically be doing the same thing they were doing before, but they would be paid a little more. And the community would be able to keep things going as they were. Nuclear power can mean continued employment, as well as a clean, affordable and reliable energy supply.”

The benefits of SMRs fit well with the needs of public power utilities, Colbert said. Instead of having to take a share in a large nuclear power plant, public power utilities can take a stake in a nuclear plant configured with the number SMRs to match their demand while having the comfort of knowing that more units could be added, if needed, in the future.

The Inflation Reduction Act also grants other benefits to public power utilities by providing a refundable direct pay credit that allows them to take advantage of tax credits that have been available to for-profit utilities for years.

The overwhelming majority of renewable energy projects have been financed using tax credits, either a PTC or an ITC. The Congressional Joint Committee on Taxation estimated that the value of energy-related tax incentives in 2022 alone would be $25 billion. Because they cannot directly benefit from tax credits, public power utilities have been left out of many of those projects.

Even before the legislation was signed, several public power utilities were considering adding an SMR plant to their generation portfolio through the deployment of NuScale’s technology.

Furthest along in embracing SMRs, however, is Utah Associated Municipal Power Systems (UAMPS), which is working toward the deployment of a NuScale VOYGR-6 SMR power plant as part of its Carbon Free Power Project at the DOE’s Idaho National Laboratory in Idaho Falls.

The prospects of the Carbon Free Power Project were bolstered in August 2020 when NuScale announced that the Nuclear Regulatory Commission (NRC) had completed the last and final phase of the Design Certification Application process for the design of its SMR technology, a crucial first step in the nuclear permitting process.

NuScale is now looking forward to reaching another milestone in the regulatory process.

In July, the NRC directed its staff to issue a final rule certifying NuScale’s SMR design.

The rulemaking would amend NRC regulations to incorporate NuScale’s SMR standard plant design, which would allow applicants intending to build and operate an SMR plant to reference the design certification rule.

“If approved, the certification would be published in the Federal Register and have the effect of law,” Colbert said.

The rulemaking is on the docket for the NRC to make a decision in November.

The timing is important.

“Many people are still wrapping their heads around the impact of the IRA,” Colbert said.

Meanwhile, the clock is ticking.

The Biden administration has set a goal for the country to reach 100 percent carbon dioxide pollution-free electricity by 2035. And the support provided by the IRA has an expiration date. The expanded ITC benefits go away in 2032 or when 75 percent decarbonization is reached.

“It is a great opportunity – the expanded ITC and the potential availability of former coal plant sites – but folks are going to need to get ahead of this if they want to ensure a secure supply of affordable, reliable electric power,” Colbert said.

Public Power Utilities in Massachusetts Enter Expanded Hydropower Power Purchase Agreement

October 16, 2022

by Paul Ciampoli
APPA News Director
October 16, 2022

FirstLight Power recently announced the expansion of a power purchase agreement with Energy New England (ENE). As part of the agreement, 13 Massachusetts-based public power entities have agreed to purchase over 110 gigawatt hours per year of hydroelectric power produced by two of FirstLight’s hydroelectric facilities in Connecticut.

The agreement will help participating communities continue to make progress toward meeting Massachusetts’ requirements for municipal utilities to obtain 50 percent of their supply from carbon-free sources by 2030 under the climate legislation passed into law in 2021.

Working in collaboration with ENE, the new power purchase agreement will run from 2024 through 2030. In addition, it expands on the successful partnership with ENE and power purchase agreement that FirstLight entered with 21 municipal utilities in 2020, which at the time represented the largest renewable energy purchase by municipal utilities in New England to date.

In 2021, FirstLight extended many of these agreements with several participating utilities including Middleborough Gas and Electric Department (MGED) and Taunton Municipal Lighting Plant (TMLP).

The public power entities participating in the contract include: Belmont Municipal Light Department, Braintree Electric Light Department, Concord Municipal Light Plant, Danvers Electric Division, Groveland Municipal Light Department, Hingham Municipal Lighting Plant, Mass Development Finance Agency (MDFA)/Devens Utilities, Merrimac Municipal Light Department, Norwood Municipal Light Department, Reading Municipal Light Department, Rowley Municipal Lighting Plant, Wellesley Municipal Light Plant, and Westfield Gas & Electric.

As part of the latest agreement with ENE, FirstLight’s Shepaug Generating Station (in Southbury, Conn) and Stevenson Generating Station (in Monroe, Conn) will supply the energy and renewable energy credits.

One of the largest hydroelectric facilities in Connecticut, Stevenson Station was recently qualified as a Class I (in Maine) renewable energy facility. As Connecticut’s largest hydroelectric generation station and the second largest source of carbon-free electricity in the state, Shepaug Station is a Maine Class II renewable energy facility.

JEA, Other Florida Utilities Sign Agreements to Join the Southeast Energy Exchange Market

October 16, 2022

by Paul Ciampoli
APPA News Director
October 16, 2022

Florida public power utility JEA and three other Florida utilities have signed agreements to join as members of the Southeast Energy Exchange Market (SEEM), effective Jan. 1, 2023.

Duke Energy Florida, JEA, Seminole Electric Cooperative and TECO Energy recently expressed their intent to join the expanded platform and expect active energy trading in mid-2023.

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

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

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

Calif. Energy Commission Updates Load Management With Call for Time Sensitive Rates

October 14, 2022

by Peter Maloney
APPA News
October 14, 2022

In a ruling that affects the state’s investor-owned utilities, as well as some of its largest public power utilities, the California Energy Commission (CEC) recently updated the state’s load management standards, including measures calling for rates that reflect costs and emissions in a more timely fashion.

Under the updated standards, which take effect April 1, 2023, Pacific Gas and Electric, Southern California Edison, San Diego Gas & Electric, Sacramento Municipal Utility District (SMUD), Los Angeles Water and Power (LADWP), and large community choice aggregators will be required to:

The updates will save consumers money by shifting usage to times of cheaper or abundant electricity, the CEC said, adding that a better-balanced grid slows the rise of electricity costs, strengthens the grid, reduces the need for more fossil fuel plants, and avoids electricity transmission and distribution congestion.

The updates also will help customers take better advantage of utilities’ lower time-dependent rates so smart appliancdes can be used and buildings can automatically respond to more frequent rate changes that reflect electricity grid conditions, the CEC said. That change will save consumers money by shifting usage to times of cheaper or abundant electricity, the CEC said.

The CEC expects the changes have the capacity to produce $243 million in net benefits over 15 years and could reduce annual peak hour electricity use by 120 gigawatt hours.

The CEC, as the state’s primary energy policy and planning agency, has statutory authority to adopt standards to help shift energy use.

Since 1978, the CEC encouraged load management through utility air conditioner cycling programs that automatically reduce use at commercial or industrial sites.

And, over time as technology has advanced, more appliances such as thermostats, pool pumps and residential water heaters have been automated to reduce use or shift time of use from high-demand hours, in response to signals from utilities and energy aggregators.

APPA Survey of Members Shows Distribution Transformer Production Not Meeting Demand

October 12, 2022

by Paul Ciampoli
APPA News Director
October 12, 2022

An American Public Power Association (APPA) survey of its members shows that production of distribution transformers is not meeting current demand, “as evident in the significantly growing lead times, lack of stock in yards and the high number of project deferrals,” APPA said.

In August 2022, APPA surveyed its members about distribution transformer supply and demand. The survey “highlights the expanded nature of this problem subsequent to the results of two previous surveys we have done on this matter, beginning in November 2021,” APPA said.

The data from the survey informed the Department of Energy and the Electric Subsector Coordinating Council (ESCC) of the severity of the supply chain distribution transformer shortage across the entire electric sector.

Ninety-five public power utilities serving a total of 6,719,596 meters responded to the survey.

Along with its finding that production is not meeting current demand, another key takeaway from the survey is that demand has grown consistently in the past and will continue to rise in the future.

 Because demand is out pacing supply, many public power utilities are at a high risk of stocking out on transformers in 2022 or following one storm.

Between 2019 and 2020, demand across all voltage classes for distribution transformers rose 3.6% for public power survey respondents. During this period, the lead time to procure distribution transformers averaged two to three months. Economic forecasts anticipate that the calculated annual growth rate for distribution transformers in North America will continue to increase and  be 9.1% for 2022-2030.

Between 2020 and 2022, the number of distribution transformers purchased remained largely steady. However, beginning in 2021 and continuing into 2022, the number of distribution transformers available for purchase no longer meets the demand. Evidence for this imbalance can be seen in the significantly increasing lead times and the deferral of projects, APPA stated.

Meanwhile, between 2020 and 2022, average lead times to procure distribution transformers for all voltage classes rose 429% for public power respondents — from about two to three months pre-2021 to about 12 months in 2022. Some utilities reported being quoted lead times of more than three years.

APPA reported that many utilities are deferring or canceling infrastructure projects because they are unable to procure the additional distribution transformers required for these projects. Among public power utilities, one in five projects were deferred or canceled.

Most responding utilities reported low or near zero emergency stock, which is often used to recover post-disaster or to do infrastructure maintenance. Some public power utilities reported being within weeks of hitting the bottom of their distribution transformer stocks. In the event of a catastrophic hurricane or other natural disaster, the industry risks stocking out much sooner, APPA pointed out.

APPA continues to work through the ESCC and other forums to discuss the problems and identify solutions that the federal government can act upon to alleviate the supply chain shortages, specifically with regards to distribution transformers.

APPA has taken a number of actions to address ongoing supply chain challenges. APPA recently rolled out an additional feature to its eReliability Tracker that is available to all public power utilities and allows for voluntary equipment sharing by matching systems with the same distribution voltages. APPA also recently finalized a new supply chain issue brief. APPA members can download the issue brief here.

In May, APPA sent a letter to Secretary Granholm at the Department of Energy asking that they consider a temporary waiver of efficiency standards in distribution transformers that may lead to an increase in supply.  That request was declined in August.  In a speech in June at APPA’s National Conference in Nashville, Tenn., APPA President and CEO Joy Ditto urged member utilities to share their supply chain challenges with APPA so that the trade group can relay details on these challenges to federal partners and discuss how critical burdens on the sector can be alleviated.

In May, APPA convened a supply chain summit that included participation from public power utility officials who discussed their supply chain challenges and mitigation strategies.

Company Looks to Extend Operation of 2,400-MW Texas Nuclear Power Plant

October 8, 2022

by Paul Ciampoli
APPA News Director
October 8, 2022

Vistra Corp. on Oct. 3 announced that it is seeking to extend the operation of Luminant’s Comanche Peak Nuclear Power Plant in Texas through 2053, an additional 20 years beyond its original licenses.

Luminant is a subsidiary of Vistra.

The company has officially submitted its application for license renewal with the Nuclear Regulatory Commission. The two-unit nuclear plant has a capacity of 2,400 megawatts.

The current licenses for units 1 and 2 extend through 2030 and 2033, respectively. The company is applying to renew the licenses through 2050 and 2053, respectively.

DOE Releases Opportunities for Nearly $5 Billion in Carbon Capture Technologies

October 8, 2022

by Peter Maloney
APPA News
October 8, 2022

The Department of Energy (DOE) recently announced nearly $4.9 billion in funding opportunities that aim to demonstrate and deploy carbon capture systems, as well as carbon dioxide transport and storage infrastructure.

The funding, which derives from the Bipartisan Infrastructure Law, is designed to support three programs.

The Carbon Storage Assurance Facility Enterprise (CarbonSAFE) initiative, which is being managed by the DOE’s Office of Fossil Energy and Carbon Management (FECM), provides up to $2.25 billion to support the development of new and expanded large-scale, commercial carbon dioxide (CO2) storage projects with capacities to store 50 or more million metric tons of CO2, along with associated CO2 transport infrastructure. Projects should focus on detailed site characterization, permitting, and construction stages of project development under CarbonSAFE.

The Carbon Capture Demonstration Projects Program, being managed by the DOE’s Office of Clean Energy Demonstrations (OCED) in partnership with FECM, will provide up to $2.54 billion to develop six integrated carbon capture, transport, and storage demonstration projects that can be replicated and deployed at fossil energy power plants and major industrial sources of CO2, such as cement, pulp and paper, iron and steel, and certain types of chemical production facilities. The funding opportunity announcement (FOA) provides up to $189 million for up to 20 integrated front-end engineering design studies, with a second FOA expected later this year to support detailed design, construction, and operation of carbon capture projects, as well as transport and storage of the captured CO2.

The Carbon Dioxide Transport Engineering and Design initiative, being managed by FECM, will provide up to $100 million to design regional CO2 pipeline networks to safely transport captured CO2 from key sources to centralized locations. Projects should focus on carbon transport costs, transport network configurations, and technical and commercial considerations that support broad efforts to develop and deploy carbon capture, conversion, and storage at commercial scale. 

DOE FOAs require that applicants submit Community Benefits Plans detailing their commitments to community and labor engagement, quality job creation, diversity and equity, and implementation of the Biden administration’s Justice40 Initiative.