Missouri River Energy Services announced that Matthew Schull has accepted the position of president and chief executive officer for the organization, effective May 12, 2023.

He will replace Thomas Heller, who has led the organization for over 30 years and will become president emeritus on May 12 ahead of his planned retirement on June 30. Schull will be introduced to the MRES membership at the Annual Meeting on May 10, 2023.

Schull served as chief operating officer of ElectriCities of North Carolina, headquartered in Raleigh, North Carolina, since May 2016. Schull joined ElectriCities in 2003 as the manager of power supply for North Carolina Municipal Power Agency Number 1 and was promoted to vice president in March 2009.

ElectriCities is a not-for-profit membership organization of municipally owned electric utilities with a mission, programs and services similar to MRES.

Prior to joining ElectriCities, Schull was employed by Progress Energy for three years, Wisconsin Energy Corporation for eight years, and Madison Gas & Electric Company for two years in various leadership, power marketing, operations and engineering roles, and has over 30 years of electric utility experience.

MRES is a joint-action agency made up of 61 member municipalities in the states of Iowa, Minnesota, North Dakota and South Dakota. MRES provides its members with wholesale electricity along with a host of energy-related services.

The Federal Energy Regulatory Commission should work to ensure that any directives FERC ultimately issues in an ongoing proceeding related to inverter-based resources and reliability capitalizes and dovetails with related work already underway by the North American Electric Reliability Corporation and the power sector, the American Public Power Association and other groups recently said.

IBRs are solar photovoltaic, wind, fuel cell and battery storage resources that use power electronic devices to change direct current power, produced by generators, to alternating current power, to be transmitted on the bulk-power system. “As use of this technology grows, it is important to ensure that IBRs do not adversely impact the technical reliability of the grid,” FERC noted last year.

The comments submitted by the groups to FERC on Feb. 6 were filed in response to a Notice of Proposed Rulemaking issued by the Commission in late 2022. In November 2022, FERC Commissioners  approved an order and a NOPR containing directives and proposed directives to the North American Electric Reliability Corporation, to account for the increasing number of IBRs in the nation’s resource mix. 

Joining APPA in the comments were the Large Public Power Council, the National Rural Electric Cooperative Association, the Transmission Access Policy Study Group and Edison Electric Institute.

The NOPR proposes to direct NERC to develop new or modified reliability standards that address the following issues related to inverter-based resources: data sharing; model validation; planning and operational studies; and performance requirements.

The trade associations said in their comments that they agree with the Commission that new or revised standards are needed to manage the impact of the rapidly increasing presence of IBRs on the Bulk Electric System. The groups “recognize, as does the Commission, that the topics addressed in this NOPR are broad and impact issues within multiple jurisdictions, including those overseen by state and local retail regulators, and coordination among them is critical.”

They said that undoubtedly, there is a category of IBRs that should be subject to certain standards.  Critical to ensuring that the reliability standards properly apply to IBRs is identifying and registering the IBRs that have a material impact on the bulk power system, APPA and the other groups said.

At the same time, the groups pointed out that NERC has launched a series of related initiatives aimed at the collection and sharing of IBR data, model validation, IBR planning and operational studies and needed IBR performance requirements. 

“While this certainly does not mean the Commission’s proposed directives are mislaid, it seems critical for NERC and the industry to be able to work cooperatively to shape these standards in ways that enhance the industry’s ability to plan and operate the grid reliably,” they said.

The groups recognize the NOPR’s proposal is to direct NERC to make a compliance filing within 90 days of any final rule explaining how it is prioritizing its IBR reliability standard projects to meet the directive in the final rule.

“We support that proposed directive, but also ask that NERC provide a plan ensuring that the significant work undertaken to date is not in vain; that the ensuing work of the drafting teams is fully informed by this work; and that the recommended standards be shaped by the work undertaken to date,” APPA and the other groups said.

The groups included details on various NERC projects relevant to the NOPR.

The groups also said that FERC should not require distribution providers and transmission owners to collect and share data and model information supporting IBR-distributed energy resources (IBR-DERs) that they cannot reasonably obtain.

With respect to sharing of IBR data, the Commission proposes that transmission owners should provide planning coordinators and other entities with detailed modeling data and parameters for unregistered IBRs with an aggregate material effect on operation of the BPS. The Commission would also require such information sharing by distribution providers for IBR-DERs.

Similarly, the Commission proposes to (1) require transmission owners to provide validated unregistered IBR models to the planning coordinators for interconnection-wide planning and operational models; and (2) require distribution providers to provide validated models of IBR-DERs in the aggregate to the planning coordinators for interconnection-wide planning and operational models. 

The NOPR recognizes that it may not be practical for distribution providers to provide modeling data and parameters to model individual IBR-DERs directly, in light of the small size and location of many of the IBR-DERs on the distribution system.

The NOPR thus proposes that distribution providers be permitted to provide IBR-DER modeling data and parameters in the aggregate or equivalent.

The groups said they appreciate that the Commission recognizes the practical challenges of modeling individual IBR-DERs. 

“But a more fundamental challenge must also be acknowledged: A registered entity cannot provide data that the registered entity itself does not have and has no ability to collect,” they said.

“In particular, it would be unrealistic to expect a transmission owner or distribution provider to have information about unregistered IBRs and IBR-DERs at the same level of detail and accuracy that registered generator owners can provide about their own facilities.”

In most if not all cases, the transmission owner or distribution provider has only the information provided to it during the interconnection approval process, APPA and the other groups said.

“Interconnection agreements may not require the IBRs to provide modeling data, and transmission owners and distribution providers may not have the contractual right to add such requirements unilaterally and retroactively. Furthermore, some IBR-DERs on the distribution system interconnect under utility retail tariffs without a separate interconnection agreement.”

The practical limitations that transmission owners and distribution providers have to collect and model data regarding unregistered IBRs and IBR-DERs are unlikely to have a significant adverse impact on BPS reliability due to a number of factors, the groups said.

In the alternative, the Commission should limit the obligations to be shouldered by distribution providers and transmission owners to what is feasible, the groups said.

“In ascertaining what it is realistic to require of transmission owners and distribution providers with respect to asset owners they do not control, the Commission may consider convening a forum to consider the relative benefits of directing new or revised reliability standards applying to distribution providers with IBR-DERs, or else directing NERC to submit a study on the challenges of developing and implementing such standards.”

The savings are approximately $4.5 million annually, a 10 percent discount on the cost of power supply contracts representing about 55 megawatts. The Clean Energy Project Bonds are valued at $841,550,000, the CCA said.

The goal of the prepayment transaction is to reduce the cost of power purchases on quantities delivered under the prepay structure with minimal risk to SVCE.

The prepay structure enables publicly owned utilities, including CCAs, to reduce their energy costs by financing the acquisition of long-term energy supplies with tax-exempt bonds. For decades, municipal utilities have used the prepayment structure as an industry standard practice to reduce costs for the purchase of natural gas.

In June 2021, four CCAs, Central Coast Community Energy, East Bay Community Energy, Marin Clean Energy and Silicon Valley Clean Energy, jointly formed the California Community Choice Financing Authority, a Joint Powers Agency.

CCCFA was created with the goal to reduce the cost of power purchases through a pre-payment structure. These prepayments allow CCAs to reduce customer costs and increase funding available for local programs.

A tax-exempt public electricity supplier, a taxable financial counterparty, and a municipal bond issuer enter into a long-term supply agreement called a Clean Energy Project Revenue Bond to pre-purchase wholesale zero-emission clean electricity from sources like solar, wind, geothermal, and hydropower.

The municipal bond issuer – in this case, CCCFA – issues tax-exempt bonds to raise the funds for the transaction, flowing the funds to the financial counterparty. The financial counterparty utilizes the bond funds and provides a discount to the CCA on the power purchases based on the difference between the taxable and tax-exempt rates.

Puget Sound Energy and Chelan County Public Utility District on Feb. 7 executed a contract for hydropower from the PUD’s two projects on the Columbia River.

The 20-year contract will increase Puget Sound Energy’s carbon-free resources toward its future renewable energy goals, as well as contributes flexible capacity to identified needs in Washington State, Chelan and Puget Sound Energy noted.

The contract was negotiated over the past 18 months and includes both carbon-free energy attributes provided by hydropower as well as flexible capacity to help PSE meet peak energy needs during high customer usage times.

The competitively priced contract provides Puget Sound Energy with 25% of the output from the PUD’s Rock Island and Rocky Reach hydropower projects from 2031 to 2051. Its current contracts with Chelan PUD, expiring in 2026 and 2031, provide a portion of the output from the two Columbia River projects.

Chelan PUD offers a mix of short-term market-based and long-term cost-based products. Both types of contracts are based on selling a “slice” of Chelan’s hydropower output.

The value of hydropower has increased as a carbon-free renewable source of energy, Chelan and Puget Sound Energy said. Those environmental attributes are in demand as companies look to satisfy new regulatory requirements through Washington State’s Climate Commitment Act and Clean Energy Transformation Act.

A Concord Municipal Light Plant pilot program for the Massachusetts-based public power utility’s heat pump adoption initiative, completed with assistance from an American Public Power Association’s Demonstration of Energy & Efficiency Developments Program grant and Energy New England, shows the value of utilizing coaches who can walk customers through the process of installing heat pumps.

The pilot program, motivated by emissions-reductions goals set by both the Town of Concord and the utility, aimed to utilize highly trained coaches to increase installation rates for residential heat pumps through one-on-one advising sessions and regular follow-up contact. The program was completed in June 2022. The utility recruited community members who had previously installed heat pumps in their own homes, with three out of four current or former coaches having installed a heat pump in the past. The fourth is in the process of installing a heat pump in his home.

Over the course of the pilot program, these coaches conducted 351 initial consultations, which far exceeded CMLP’s goal of 150. Of those consultations, 17 percent resulted in a client installing a heat pump. By November 2022, that percentage had increased to 26 percent.

CMLP took care to prepare coaches for the demands of walking customers through a complicated, lengthy, and expensive process. Jan Aceti, Energy Conservation Coordinator with CMLP, noted the importance of coaches being both well trained and sufficiently supported, saying, “I do feel that it’s important for the coaches to feel that not only can they get expert technical advice when they need it, but that [the utility] is available to talk with them about complex issues like rebate eligibility.”

The coaches played a key role in guiding clients through the process, particularly when factors such as the home’s age necessitated a Home Energy Assessment—conducted by ENE—to determine whether a home needed improvements to insulation, windows, or weatherization before installing a heat pump.

As a technology with which many customers remain unfamiliar, heat pumps represented an area where knowledgeable, non-financially motivated consultants proved highly successful. Surveys of coaching clients saw a nine out of ten customer satisfaction rating, with 90 percent of those clients saying they would recommend the service to others.

Among CMLP’s primary motivations for this program was the ambitious emissions-reductions targets set by the Town of Concord and the utility. Per Noel Chambers, Director, Energy Efficiency and Electrification with ENE, Massachusetts has “very aggressive goals and very aggressive timelines [for emissions reductions],” and CMLP sees increased adoption of heat pumps as a key method for achieving those goals.

CMLP’s DEED report states an aim of 180 installations each year to meet its 2050 emissions targets, but the utility saw only 71 documented installations in 2021, the first year of its pilot. The utility’s pilot period concluded in June 2022, and, at the time of its final report publication, it had documented 136 installations. By the end of 2022, however, the total number of documented installations jumped to 178, with particular growth seen in the percentage of coaching-assisted installations, rising from 34 percent in 2021 to 50 percent in the first half of 2022 and 61 percent during the second half of the year.

Aceti and Chambers both noted the value of DEED grants for smaller utilities like CMLP. Aceti said the program “lends a lot of legitimacy,” serving as a guarantee to the utility and its customers that CMLP is “responsible for carrying that project to fruition.”

Chambers, speaking more broadly, emphasized the importance of putting public power utilities—particularly smaller utilities—on more level footing with investor-owned utilities: “IOUs have…the capability and ability built into their programs to conduct one-off, exploratory projects. An individual light plant – it would be impossible to develop these programs without grant funding [from programs like DEED].”

CMLP received $37,987.94 via the DEED grant and provided $33,535.53 In training and wages for the heat pump coaches, in addition to $47,212.84 in labor hours contributed by CMLP’s Energy Conservation Coordinator. Some of the coordinator’s responsibilities included assigning clients to coaches, working with the coaches to develop coaching procedures and tools, and marketing the coaching service. Though budgeted for $12,000, ENE’s financial contribution ended up being only a fraction of that amount at $250, largely because other pilot project priorities left less time than expected to work on integrating the heat pump coaching service and the home energy assessment service.

The utility plans to continue the project with an expanded in-house budget for 2023, and CMLP has considered offering wholesale decarbonization coaching services for clients in the future.

Concord Municipal Light Plant provides electric service to 6,995 residential and 1,280 commercial and municipal customers in the town of Concord. The utility does not generate any power, and therefore works to purchase as much energy as possible from non-emitting energy sources.

Energy New England is a joint action agency serving 29 utility providers across Connecticut, Rhode Island, Massachusetts, Vermont, and Maine. Among other member services, ENE currently conducts HEAs for 20 members, oversees rebate programs for 12 members, and provides an electric vehicle support service for 12 communities.

APPA’s Demonstration of Energy & Efficiency Developments program funds research, pilot projects, and education to improve the operations and services of public power utilities, with particular emphasis placed on the scalability and transferability of projects for other utilities. For more information on APPA’s DEED program, to become a DEED member, or to apply for a DEED grant, visit the DEED program’s webpage.

The U.S. Department of Energy on Feb. 8 announced a funding opportunity of up to $74 million for up to seven pilot projects that will test the efficacy and scalability of enhanced geothermal systems.

“Through this investment, DOE hopes the research and development from the findings would demonstrate the growth and ultimate potential for geothermal energy to provide reliable, around-the-clock electricity to tens of millions of homes across the country,” DOE said.

This is DOE’s first funding opportunity for geothermal energy since the launch of the Enhanced Geothermal ShotTM , part of DOE’s Energy EarthShots Initiative, which seeks to cut the cost of geothermal energy 90% by 2035. 

Geothermal energy currently generates about 3.7 gigawatts of electricity in the United States, but a new analysis shows it could provide 90 gigawatts of firm, flexible power to the U.S. grid by 2050, as well as heating and cooling solutions nationwide. This substantial geothermal energy potential is, however, largely inaccessible with conventional geothermal technologies, DOE said.

Applications for the pilot demonstrations will be accepted over multiple rounds. First-round letters of intent are due March 8, 2023, and first-round applications will be due July 7, 2023. 

DOE is providing a voluntary Teaming Partner List where interested parties can provide contact information and their expertise for use in forming partnerships in order to help a broad and inclusive range of interested entities apply.

Click here for additional details on the funding opportunity.

While lithium-ion technology has been king of the hill when it comes to energy storage options for utilities, this year could prove to be a key inflection point for the emergence of alternative energy storage technologies in the U.S. if recent developments are any indication.

For several years, lithium-ion batteries have dominated the energy storage landscape for electric utilities, but one of the limitations of lithium-ion batteries is the limited amount of storage hours they can provide. And there have also been safety concerns raised about fires occurring at lithium-ion facilities.

There is a wide array of storage technologies that differentiate themselves from lithium ion by offering longer storage durations, which is becoming increasingly important as intermittent renewable energy sources continue to expand across the U.S. power grid.

“The value of long-duration energy storage, which helps address variability in renewable energy supply across days and seasons, is poised to grow significantly as power systems shift to larger shares of variable generation such as wind and solar,” a report posted on the National Renewable Energy Laboratory notes.

IRON FLOW BATTERIES

One of the companies making a splash in the iron flow battery space in recent months is ESS Inc. Two California public power utilities, SMUD and Burbank Water and Power, in 2022 announced agreements with ESS.

SMUD and ESS on Sept. 20, 2022 announced an agreement to provide up to 200 megawatts (MW)/2 gigawatt-hours (GWh) of long duration energy storage that will be provided by ESS. The agreement calls for ESS to deliver a mix of its long-duration energy storage technology for integration with the SMUD electric grid beginning in 2023.

In November, ESS and Burbank Water and Power entered into an agreement for ESS to deliver BWP’s first utility-scale battery storage project. Under the agreement, a 75 kilowatt (kW)/500 kilowatt hour kWh ESS “Energy Warehouse” will be installed and connected to a 265 kW solar array on BWP’s EcoCampus.

The iron flow battery will support the increased use of renewable power and allow excess renewable energy to be stored and used as baseload energy for Burbank, improving the resilience and reliability of the grid.

IRON AIR AND COMPRESSED AIR BATTERIES

In late January, Form Energy announced that it had entered into definitive agreements with investor-owned Xcel Energy to deploy Form Energy’s iron-air battery systems at two of Xcel Energy’s retiring coal plant sites.

Xcel Energy–Minnesota will deploy a 10 MW/1,000 MWh multi-day storage system at the Sherburne County Generating Station in Becker, Minnesota. 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.

In December, West Virginia Gov. Jim Justice announced that Form Energy will partner with the state of West Virginia to build its first iron-air battery manufacturing facility on 55 acres of property in the northern panhandle of West Virginia, along the Ohio River.

Meanwhile, California community choice aggregator Central Coast Community Energy in January said that it signed a 25-year power purchase agreement for a compressed air energy storage project with Hydrostor.

The nearly $1 billion power purchase agreement calls for the delivery of 200 megawatts, 1,600-megawatt hours of energy storage to 3CE from Hydrostor’s planned Willow Rock Energy Storage Center that will use the company’s Advanced Compressed Air Energy Storage technology. Hydrostor says the project, when completed, will abate up to 28 million metric tons of carbon dioxide over its lifetime.

Hydrodstor’s technology combines elements of a compressed air storage system with a pumped hydro system. The process stores energy as compressed air but captures and stores the heat of compression for future use. The compressed air is stored in a purpose-built underground cavern that uses a water reservoir to maintain constant pressure. The facility discharges energy by reversing the process, using the stored heat and pressure to power a conventional turbine generator. The system has no performance degradation over its 50-year plus expected lifetime, Hydrostor said.

Hydrostor said its technology offers the same services as a natural gas plant while having zero emissions because it uses surplus electricity as fuel. The company is targeting high value grid applications such as transmission deferral and fossil fuel generation replacement.

HYDROGEN

In early January, Energy Vault Holdings, Inc. and California investor-owned utility Pacific Gas and Electric announced the companies are partnering to deploy and operate a utility-scale battery plus green hydrogen long-duration energy storage system with a minimum of 293 megawatt-hours of dispatchable energy.

The system is designed to power downtown and the surrounding area of the City of Calistoga, Calif, for a minimum of 48 hours during planned outages and potential Public Safety Power Shutoffs, which is when the powerlines serving the surrounding area must be turned off for safety due to high wildfire risk.

PG&E submitted the project contract for review and approval to the California Public Utilities Commission on December 30, 2022, with a request for the issuance of a final resolution approving the project by May 15, 2023.

The energy storage system will be owned, operated and maintained by Energy Vault while providing dispatchable power under a long-term tolling agreement with PG&E.

The system’s capacity may be expanded to 700 MWh, which would allow it to operate for longer without refueling, enabling further flexibility for PG&E and the City of Calistoga.

Energy Vault’s system will replace the typical, mobile diesel generators used to energize PG&E’s Calistoga microgrid during broader grid outages.

Construction is anticipated to begin in the fourth quarter of 2023 with commercial operation expected by the end of second quarter of 2024.

Upon completion, this project is expected to be the first-of-its-kind and the largest utility-scale green hydrogen project in the United States.

Los Angeles Department of Water and Power

The Los Angeles Department of Water and Power told Public Power Current that it recognizes the benefits of green hydrogen as a “power-to-gas” long-duration energy storage solution, through the use of electrolyzers, a system that uses electricity to break water into hydrogen and oxygen in a process called electrolysis.

LADWP was asked to provide additional details on where things currently stand in terms of LADWP’s possible pursuit of green hydrogen for storage.

As a purchaser of power produced by the Intermountain Power Project (IPP), LADWP is involved in installing two, 420 MW each, combined cycle generating units at IPP that will be capable of using hydrogen fuel (blended with natural gas) when placed in service in July 2025. The hydrogen will be produced using renewable energy and electrolyzers, and then stored in salt caverns for long-duration energy storage that can store and provide a seasonal supply of hydrogen, LADWP officials noted.

LADWP does not plan to be directly involved in the production of green hydrogen in the Los Angeles area at this time, but it will work with energy developers to implement green hydrogen projects to provide grid reliability and a zero carbon energy source.

LADWP officials said that its strategic long-term resource plan includes options for eventually purchasing green hydrogen from the market to spur development of green hydrogen capacity in the Los Angeles area.

The utility believes this technology is necessary to ensure the power system remains resilient during emergency events, such as an earthquake, wildfire, or other situations when clean dispatchable generation capacity may be necessary to maintain grid reliability and resiliency as it transitions to 100% clean energy.

LADWP officials said the utility is looking at a variety of energy storage technologies as well as green hydrogen as its transition to a 100% clean energy future.

The officials said the utility will need energy storage to mitigate the intermittent generation challenge posed by renewable resources (variable wind and solar) and to provide resources for periods of low renewable generation, high energy demand periods, and loss of generation and/or transmission lines to maintain grid reliability and resiliency.

LADWP officials point out that there are trade-offs with different technologies: Batteries are limited in their ability to store large quantities of energy economically and shift the energy beyond the daily or hourly timeframe. Pumped hydro is limited by location (it is challenging to find new sites for large hydroelectric plants) and is constrained by water availability, the officials noted.

Green hydrogen offers the potential for long-duration energy storage that uses excess renewables available in the spring when electricity demand is low to produce hydrogen for use in the summer when electricity demand is high — referred to as seasonal storage, they said. Another benefit is that, in some cases, the existing power generating units can be modified to use green hydrogen.

As the green hydrogen economy scales up, LADPW expects that it will become a viable, low-cost solution for seasonal energy storage that offers the flexibility to decarbonize the electric grid and other sectors of the economy.

Orlando Utilities Commission Explores Deployment of Long-Duration Energy Storage Facility

In early January, Florida public power utility Orlando Utilities Commission said it will explore deployment of a long-duration energy storage facility as a way in which to help achieve the utility’s net-zero carbon emission goals.

The facility will be provided by Malta Inc. Malta’s storage technology converts excess electricity into thermal energy that is stored in salt and coolant. When needed, the plant regenerates gigawatt hours of electricity for residential and commercial use.

The Malta facility would be situated at OUC’s Indian River Plant in Brevard County on Florida’s East Coast.

Malta’s more than 100-megawatt utility-scale system provides more hours of energy storage than lithium-ion batteries and could provide energy storage diversity for OUC. The increased duration facility has the potential to help OUC ensure grid reliability despite the variable nature of clean and renewable energy resources like solar.

NYPA Signs Agreement for Planned Deployment of Zinc-Air Storage System

Another public power utility pursuing long-duration energy storage technology is the New York Power Authority.

In April 2021, NYPA signed an agreement with Zinc8 Energy Solutions Inc. and the University at Buffalo for the planned deployment of Zinc8’s zinc-air energy storage system, marking a first demonstration of a long-duration use in New York State and a development that could support further integration of renewable power sources into the electric grid.

In January 2022, New York Gov. Kathy Hochul announced that Zinc8 will relocate its $68 million manufacturing facility and U.S. headquarters to Kingston, N.Y.

Zinc8’s technology has been developed around the utilization of zinc as the anode fuel, which is expected to offer advantages over other metals due to its high energy density, abundant availability, low cost, and ease of storage and handling.

When the system is delivering power, the zinc particles are combined with oxygen drawn from the surrounding air. When the system is recharging, zinc particles are regenerated, and oxygen is returned to the surrounding air. The regenerative system does not require fuel replacement and offers scalable energy capacity through the simple introduction of additional fuel tanks.

Wisconsin Utility Pilot Project Tests New Form of Long-Duration Energy Storage

In early February, WEC Energy Group, a Wisconsin-based investor-owned utility, announced that the company will lead a pilot project at its Valley Power Plant in Milwaukee to test a new form of long-duration energy storage.

WEC Energy Group is collaborating with the Electric Power Research Institute and CMBlu Energy, the developer and manufacturer of the long-duration battery based in California and Germany.

This 1-to-2-megawatt-hour pilot project will be one of the first to test this type of energy storage system on the U.S. electric grid, WEC Energy Group said.

The CMBlu Organic SolidFlow energy storage system uses a proprietary flow battery technology with components from recyclable materials.

The project will test the performance of the battery system, including discharge durations of five to 10 hours — up to twice as long as the typical lithium-ion batteries in use today.

The pilot project is planned for testing in the fourth quarter of this year.

Findings will be shared with the utility industry. EPRI will share a complete analysis of the project in early 2024.

APPA Storage Tracker

The American Public Power Association’s Public Power Energy Tracker is a resource for association members that summarizes public power energy storage projects that are currently online. The tracker is available here.

APPA Energy Storage Working Group

APPA’s Energy Storage Working Group (ESWG) is part of a cooperative agreement between APPA and the Department of Energy (DOE) Office of Fossil Energy and Carbon Management to lower barriers to integrating battery storage with the operation of fossil fuel generation assets.

In 2022, the ESWG developed a report on energy storage challenges, solutions, and opportunities for public power.

APPA is continuing to convene members to get feedback, advice, and other input on the energy storage challenges and opportunities for integrating energy storage. The next ESWG virtual meeting is scheduled for February 23, 2023, from 2 – 3:30 PM ET. The main goal for the meeting will be to discuss the baselines for an energy storage maturity model framework.

If you are interested in joining or learning more about the Energy Storage Working Group, please contact EnergyTransition@PublicPower.org.

In a Feb. 6 letter to the Federal Energy Regulatory Commission, California Gov. Gavin Newsom asks FERC to “immediately focus its investigatory resources on assessing whether market manipulation, anticompetitive behavior, or other anomalous activities are driving these ongoing elevated prices in the western gas markets.”

In his letter to Acting FERC Chairman Willie Phillips, Newsom said that since late November 2022, wholesale natural gas prices throughout the West “have risen to alarming levels that greatly exceed prices in the rest of the country.”

Newsom said that electricity prices in the FERC-regulated California Independent System Operator Market and Western Energy Imbalance Market “have similarly escalated because electricity prices are directly affected by wholesale natural gas costs.”

He said that while wholesale natural gas price increases were exacerbated by early cold weather
in the western states, “those known factors cannot explain the extent and longevity
of the price spike.”

The extended high prices have prompted the California Public Utilities Commission and the California Energy Commission to convene an en banc meeting with market experts from across the country to explore all the possible drivers behind the wholesale natural gas price spikes, as well as any measures that could protect electric and gas utility customers, Newsom noted.

“However, it is clear that the root causes of these extraordinary prices warrant further examination,” he said.

“I therefore ask that FERC immediately focus its investigatory resources on assessing whether market manipulation, anticompetitive behavior, or other anomalous activities are driving these ongoing elevated prices in the western gas markets,” he said.

“And, if warranted, I ask that FERC bring its full enforcement powers and resources to bear to
protect customers. I also offer California’s resources to assist in any data collection that FERC may require.”

The California Municipal Utilities Association has been awarded $4 million from the California Workforce Development Board’s High Road Training Partnership Grant Program to implement the new California Water, Wastewater, and Energy Workforce Development Program.

The grant will develop a statewide workforce development program focused on diversity, equity, and inclusion resulting in trained workers who will secure jobs in the public power utility, water and wastewater industry throughout California, CMUA said.

There are three major components of the program, all of which will positively impact CMUA members:
 
Literature Review and Supplemental Needs Assessment: CMUA will facilitate a literature review of existing and planned workforce surveys to determine if additional work is needed to serve members’ needs and establish a solid foundation for implementing the Program.

Develop, Pilot, and Implement Regional Consortium: Based on the needs assessment and a separate evaluation of other factors that would support success, one area in California will be selected for a regional consortium that connects CMUA members to workers, community colleges and universities and other interested parties. CMUA also will work with the workforce development board in the selected region to run a pilot program supporting new entrants into the industry, particularly from underserved communities.

Statewide Activities: The program also will include statewide activities benefitting members, including materials members can use for outreach and awareness of the industry; best workforce development practices for industry utilities; and grants for training at partner organizations and other stakeholders with existing training programs.

CMUA said it will discuss with the workforce development board how CMUA members can access grant funds directly. “Still, there is significant funding for existing training organizations to expand their efforts and ensure additional trained workers are available for hire by member utilities,” CMUA said.

CMUA’s next step is to hire grant administration/project management staff and it will collaborate with a large coalition of trade associations, nonprofits, and vocational organizations to implement the elements of the grant.