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MEAG Power Names Reiko Kerr As New Senior Vice President and Chief Financial Officer

May 21, 2022

by Paul Ciampoli
APPA News Director
May 21, 2022

MEAG Power on May 20 announced that Reiko Kerr has been named senior vice president and chief financial officer, filling the vacancy resulting from Edward Easterlin’s recent retirement.

Kerr joins MEAG Power from the Los Angeles Department of Water and Power (LADWP), where she was senior assistant general manager. She will join MEAG Power effective July 18.

Kerr has 22 years of utility industry experience in public power, including 16 years at Riverside Public Utilities (RPU) in Riverside, Calif. She served as chief financial officer at RPU, among other executive positions in power supply and risk management, before joining LADWP in 2016.

Georgia-based MEAG Power is a nonprofit, statewide generation and transmission joint action agency. MEAG Power has over $9 billion in assets, delivered 10.6 million megawatt-hours of energy in 2014, and owns more than 1,300 miles of high-voltage transmission lines and nearly 200 substations.

NERC Summer Assessment Sees ‘Elevated’ Reliability Risks In The West, MISO

May 21, 2022

by Peter Maloney
APPA News
May 21, 2022

Parts of western North America face an “elevated or high risk” of energy shortfalls this summer because of predicted above-normal temperatures and drought conditions and electric reliability in the Midcontinent ISO (MISO) is at “high risk” because of capacity shortfalls, according to the 2022 Summer Reliability Assessment released by the North American Electric Reliability Corp. (NERC).

The expected continuation of western drought conditions poses several threats to electric reliability, NERC said. Below normal snowpack can result in lower-than-average output from hydro generation in a region that depends on energy transfers to balance electric supply and demand.

In particular, the California-Mexico (CA/MX) assessment area and the Southwest Reserve Sharing Group (SRSG), depend on “substantial electricity imports” to meet demand on hot summer evenings and at times when wind and solar resources are low.

Texas, the Southwest Power Pool (SPP), and Saskatchewan, in particular, are at elevated risk of energy emergencies during extreme conditions, the NERC report said, pointing out that in addition to putting a strain on electrical equipment, high temperatures also contribute to high demand.

The report also noted that continuing drought conditions over the Missouri River Basin could adversely affect SPP thermal generators that use the Missouri River for cooling.

Drought conditions can also exacerbate wildfires, NERC said, noting that government agencies are warning of the potential for above-normal wildfire risk across much of Canada, the U.S. South Central states, and Northern California. Wildfires can affect the reliability of transmission lines and the smoke from wildfires can cause diminished output from solar power resources, NERC said.

NERC also warned that the risk of unexpected tripping of solar photovoltaic resources during grid disturbances continues to be a reliability concern. In May and June of 2021, Texas experienced widespread solar loss events like those previously observed in California and four additional solar loss events occurred between June and August 2021 in California. During these events, widespread loss of solar resources was coupled with the loss of synchronous generation, unintended interactions with remedial action schemes, and some tripping of distributed energy resources, NERC said.

NERC also singled out the risks facing MISO, saying the region is at “high risk” because it faces capacity shortfalls in its north and central areas during both normal and extreme conditions because of generator retirements and increased demand.

Load serving entities in four of 11 MISO zones entered the annual planning resource auction (PRA) in April 2022 without enough owned or contracted capacity to cover their requirements, and peak demand projections have increased by 1.7 percent since last summer due in part to a return to normal demand patterns that were altered during the pandemic.

Even more impactful, NERC said, is the drop in capacity in the most recent PRA. MISO will have 3,200 megawatts (MW), representing 2.3 percent, less generation capacity than in the summer of 2021.

In addition, at the start of the summer, MISO will be without a transmission line connecting its northern and southern areas as restoration continues on a four-mile section of a 500-kilovolt (kV) transmission line that was damaged by a tornado in December 2021.

MISO system operators “are more likely to need operating mitigations, such as load modifying resources or non-firm imports, to meet reserve requirements under normal peak summer conditions,” NERC said. If there are extreme temperatures, higher generation outages, or low wind conditions MISO’s north and central areas will be exposed to “higher risk of temporary operator-initiated load shedding to maintain system reliability,” the NERC report said.

Supply chain issues and challenges commissioning new resources are also a concern in areas where those resources are needed for reliability during summer peak periods, NERC said. The report identified CA/MX and SRSG as areas that have “sizeable amounts of generation capacity in development and included in their resource projections for summer.”

In addition, coal-fired generators are having difficulty obtaining fuel and non-fuel consumables as supply chains are stressed, NERC said.

While no specific reliability impacts are foreseen, coal stockpiles at power plants are relatively low compared with historical levels, and some operators report challenges in arranging replenishment due to mine closures, rail shipping limitations, and increased coal exports, the report said.

Outside of MISO and the Western Interconnection, all other regions have sufficient resources to manage normal summer peak demand and are at low risk of energy shortfalls from more extreme demand or generation outage conditions, the report said.

The entire electric system, however, faces cyber security threats from Russia and other potential actors amid heightened geopolitical tensions in addition to ongoing cyber risks. “Russian attackers may be planning or attempting malicious cyber activity to gain access and disrupt the electric grid in North America in retaliation for support to Ukraine,” the NERC report said.

The Electricity Infrastructure Sharing and Analysis Center (E-ISAC) continues to exchange information on cyber threats with members and post communications and guidance from government partners.

E-ISAC members are “encouraged to check in regularly to receive updates and to actively share information regarding threats and other malicious activities with the E-ISAC to enable broader communication with other sector participants and government partners,” NERC said in its summer assessment.

Public Power Utilities Respond To Supply Challenges, Detail Mitigation Strategies

May 19, 2022

by Paul Ciampoli
APPA News Director
May 19, 2022

Public power utilities across the country continue to grapple with supply chain issues across a range of materials but they are proactively responding to this challenge through a wide range of mitigation strategies.

Those challenges and mitigation strategies were detailed recently at the American Public Power Association’s (APPA) Supply Chain & Management Summit, which was held on May 5-6, 2022.

 [This is the first of a two-part series detailing public power’s response to supply challenges].

At the summit on May 5, Edward Thomas, Jr., Manager, Materials Demand, at Florida’s Orlando Utilities Commission (OUC), noted that utilities “have a strong track record when it comes to recovery preparations for weather events and natural disasters.”

However, the health crisis caused by COVID-19 “created some unique challenges” that he said were foreign to the industry such as widespread quarantines, workforce and supply chain disruptions “that further complicated our traditional contingency plans,” he said.

With respect to raw material shortages, Thomas said that low inventories have caused cascading issues with material production with manufacturers. There is also a backlog of orders. “Suppliers have reported to us that it is the sheer amount of demand for materials compounded by the shortages in skilled labor.”

As for the primary materials impacted by the supply chain crunch, Thomas mentioned transformers and switchgear, wire and cable, water meter and meter boxes and lids. Chemicals are also be affected. He noted in his presentation that during the height of the pandemic, OUC experienced shortages of oxygen used in its water plants to ozonate the water for disinfection and removal of hydrogen sulfide.

While the current state of the supply chain has presented a host of challenges, it also offers opportunities, Thomas said.

The way things have been done before “and business as usual is not an option for us any longer,” he said.

Thomas said in his presentation that there is increasing pressure on utilities, suppliers and manufacturers to transform and evaluate and review the planning of capital projects as well as regular scheduled maintenance.

He also highlighted communicating with strategic supply chain stakeholders on volume for the next quarter when available, which includes materials, utility planning, suppliers, manufacturers and customers.  

In outlining supply chain mitigation strategies and potential solutions, Thomas highlighted OUC’s strategic partnerships with suppliers and manufacturers. The utility holds monthly scheduled meetings with operations, suppliers and manufacturers to discuss orders and any delays. OUC has also collaborated with suppliers “to hold material at their location based on annual monthly usage, while our project orders were being shipped direct.”

OUC is also working to educate and notify developers and builders within its service area. A letter was drafted with assistance of OUC marketing and communications updating customers about delays and adjusting materials allocated for their specific phased projects, Thomas said.

Another summit panelist, Hud Allworth, Manager, Materials Management and Warehouse, at Washington State’s Snohomish PUD, noted that supply chain issues created more noticeable impacts to a wider range of materials by mid-2021.

Many materials providers and manufacturers were still closed or had reduced production. Others had difficulty ramping production back up, saw supply shortages, experienced transportation pressures and faced labor shortages.

Suppliers began notifying the PUD that lead times were increasing, Allworth said. “In September 2021, we went to our Board of Commissioners and asked for an emergency declaration” to address the supply chain pressures.

In his presentation, he listed the following critical materials impacted by the supply chain crunch:

With respect to mitigation strategies, Allworth noted the following in his presentation:

“We expect continued supply chain disruption” and anticipate this will remain a top priority for the PUD into 2023, he said.

Jeffrey Stewart, Director for Louisiana public power utility Lafayette Utilities System (LUS), spoke at the summit on May 6.

He noted that since 2017, Louisiana has been hit by tropical storms and hurricanes and detailed existing mutual aid activities involving LUS. Currently, mutual aid only covers labor and equipment necessary for power restoration, Stewart said.

APPA helps to coordinate mutual aid events and offers resources to its members related to mutual aid.

Mutual aid efforts have “strengthened the relationship of APPA members over time,” Stewart said. “The last thing we all want to do is experience a hurricane, but it happens. It’s part of what we do. It’s part of how we operate and getting the assistance from up to 2,000 other members is a huge, huge benefit to being a part of APPA.”

With respect to supply chain issues, Stewart said that LUS is seeing increased prices and a shortage of material across a range of areas. He noted a shortage of supplies in things like transformers and fleet vehicles.

LUS is “trying to find creative ways to get our material.” The utility is looking at the option of leasing standard vehicles and trucks. “We’ve discussed the idea of setting aside material” for storms. But there are not “a whole lot of solutions because the supply isn’t there to implement some things.”

Mutual Aid for Materials  

Stewart touted the idea of creating mutual aid for materials, “just like we do for the labor and equipment, especially during hurricane season.”

This would involve one centralized location for finding available materials and utilize three tiers of materials.

As things stand today, if a utility needs a specific type of transformer at a certain voltage level, “it may be 25, 35, a hundred phone calls before I can find anything and that’s regardless of material supply shortages or anything like that,” he said. “I don’t know everybody’s operating voltage.”

Other Public Power Utilities Also Addressing Supply Chain Challenges

Other public power utilities have also been grappling with supply chain issues.

In September 2021, Texas public power utility CPS Energy issued a news release noting that the coronavirus pandemic, labor shortages, and other events have caused major production interruptions for many manufacturers at an international scale.

“Current demand for products and supplies are dramatically exceeding the available supply, which is putting a strain on supplies that CPS Energy and other utilities use daily,” the utility said at the time.

CPS Energy said that an increasing list of raw materials were causing challenges for manufacturing including:

“CPS Energy is working diligently to minimize the impact of material supply shortages,” it said, noting that CPS Energy was taking a highly creative approach to the materials shortage challenges.

“These supply constraints are not unique to our community,” said Maria Garcia, CPS Energy’s Vice President of Supply Chain, in the news release. “Our peer utilities across the country are taking similar actions to ours such as diversifying their specifications and suppliers to allow for greater flexibility in procuring these critical items, without sacrificing product safety, resiliency and reliability.”

In a May 10 email update, CPS Energy spokesperson Dana Sotoodeh said it is important to note that when discussing supply chain challenges that San Antonio is one of the fastest growing metros in the nation.

She detailed the following general updates: 

CPS Energy has responded by diversifying its supplier base, expediting shipments where possible, negotiating contracts to keep current pricing in place and refurbishing equipment to increase its lifespan.

The utility is also:

New Braunfels Utilities

Another Texas public power utility, New Braunfels Utilities (NBU), posted a supply chain alert on its website in which it noted that developers of new construction are impacted due to material shortages for distribution wire, cable, and transformers to complete planned developments. “Lead time for these materials is now calculated in months rather than days. Buyers at NBU are working diligently to source these materials and find alternate sourcing when available,” the utility said in the alert.

NBU said that it had been notified by multiple vendors that its contracted deliveries of wire, transformers, and other equipment were significantly delayed due to dock delays, labor shortages, and other issues. In some instances, they are citing delays of up to 100 weeks, the utility noted.

“These delays of needed material and equipment will affect the start date for new construction projects,” NBU said.

It pointed out that it “is working diligently to locate alternative sources for the equipment needed to proceed with new construction projects. Our purchasing team is dedicated to finding additional vendors and materials to keep project delays to a minimum.”

To help mitigate the impact of supply chain issues, “any and all developer requirements must be completed prior to material and equipment being reserved. This means all easements, fees, and civil work are required to be completed before NBU will release a project to Purchasing to confirm the needed materials are available.”

Public Power Weighs In On Hydropower Licensing Issues At House Hearing

May 19, 2022

by Paul Ciampoli
APPA News Director
May 19, 2022

Rich Wallen, General Manager and CEO of Washington State’s Grant County PUD, recently warned of the negative consequences that could result from the removal of the Lower Snake River Dams in testimony he gave at a House hearing that examined proposed hydropower licensing changes.

Meanwhile, the American Public Power Association (APPA) said in a statement for the record for the hearing that the process for licensing non-federal hydro projects must be streamlined and reformed.

The hearing was held on May 12 by the House Energy and Commerce Committee’s Subcommittee on Energy.

Along with Wallen, other hearing participants were Malcolm Woolf, President & CEO, National Hydropower Association, Tom Kiernan, CEO, American Rivers, Mary Pavel, Partner, Sonosky, Chambers, Sachse, Endreson & Perry LLC, and Chris Wood, President & CEO, Trout Unlimited.

The primary focus of the hearing was to examine hydropower licensing and proposed changes recently put forth by groups involved in the “Uncommon Dialogue” effort, a forum created by the Stanford Woods Institute to bring together stakeholders to develop consensus policy, technology, and investment recommendations related to hydropower, river health, and dam safety.

Grant County PUD owns and operates two Columbia River dams and two smaller hydro generators that have a combined generating capacity of more than 2,100 megawatts. Priest Rapids and Wanapum dams, collectively known as the Priest Rapids Project, are licensed by the Federal Energy Regulatory Commission (FERC).

In his testimony, Wallen noted that the PUD supports H.R. 1588, the Hydropower Clean Energy Future Act, sponsored by Rep. Cathy McMorris Rogers, R-Wash.

The recently completed Columbia River System Operation Environmental Impact Statement studied the environmental, biological, power supply and socioeconomic impacts of the entire Federal Columbia Rivers System Operations. 

While one of the proposed alternatives was breeching the Lower Snake River Dams, the conclusion of the study was that the dams play a vital role in the Northwest power system and that their continued operation does not inhibit the existence of endangered or threatened salmon species.

“While we recognize some of the removal efforts contemplated under the Uncommon Dialogue are for non-powered dams, the predominance of dam removal in the dialogue at all is concerning,” Wallen told lawmakers at the hearing.

He pointed out that the Lower Snake River Dams were built to facilitate fish passage and actually achieve spring juvenile survival rates at 96% and summer migrating fish survival at 93%, meeting or exceeding performance standards. 

“Nonetheless, some stakeholders push for removal of the Lower Snake River Dams even though the fish in the neighboring undammed rivers are experiencing similar stresses and the fact that only three of the listed species even migrate up the Snake,” Wallen said.

The four Lower Snake River Dams are a critically vital component of the Bonneville Power Administration’s (BPA) low cost, carbon-free power supply, he went on to say.

“To remove the dams would result in massive rate increases to regional supply costs, increases in carbon emissions and increased risk of blackouts,” he said. “Replacement carbon-free resources are not available and cannot be easily or cheaply secured and require overbuild to counteract their intermittency.”

Under this future, the Lower Snake River Dams “will grow in importance, because they can act as giant, clean energy batteries, helping fill in these gaps for wind and solar.”

Wallen said that hydropower “provides dependable and carbon-free generation, when we need it and how we need it.”

While Grant PUD owns and operates its own hydropower dams, “we are concerned about the impact losing the Lower Snake would have for the entire region.”

He noted that the Western Electric Coordinating Council in its 2021 Western Assessment of Resource Adequacy issued a warning that every region comprising the Western grid is facing an abnormal risk of blackouts.

“We are also concerned about the price impacts, as the BPA has forecasted wholesale price impacts of 50% if the dams are removed and replaced with wind or solar plus batteries,” Wallen said. “This price hike could impact Grant PUD customers,” he said, noting that the PUD has priority rights to BPA-provided generation.

“In a carbon-constrained world, hydropower is increasingly vital for its emissions-free generation, load-following capabilities, grid stability and integrating intermittent resources that keep the lights on,” Wallen said.

APPA Statement For the Record

In its Statement for the Record, APPA noted that there is a significant potential for new hydropower to be generated at non-powered dams throughout the country and to increase output at existing hydropower facilities. “But there are excessive barriers to tapping this potential,” it said.

The Federal Energy Regulatory Commission (FERC) is the primary federal agency responsible for the licensing and relicensing of such non-federal hydroelectric projects, “but the process can be lengthy, difficult, costly, and uncertain for applicants,” APPA said.

It noted that under the Federal Power Act (FPA), FERC must establish requirements in conjunction with the license that give “equal consideration” to not only power needs, but also Endangered Species Act requirements, water quality issues, marine navigation, and other public-interest concerns. FERC must carefully evaluate many aspects of a hydropower project, but at the same time, state and federal agencies can impose “mandatory conditions” that FERC cannot balance or modify in the public interest.

“While it is appropriate to consider a broad array of factors, this process must be streamlined and reformed. Critical new additions to existing hydropower facilities are languishing under bureaucratic and often contradictory processes that can span a decade or more or which simply become too costly,” APPA said. “The byzantine licensing and permitting processes are also a significant impediment to simply maintaining existing hydropower capacity.”

Between now and 2030, 281 facilities representing nearly 14 gigawatts of hydropower generation and pumped storage capacity — roughly 30 percent of FERC hydropower licenses — are up for relicensing.

“We simply cannot afford to lose existing hydropower capacity without threatening to miss emission reduction goals and grid resiliency. Congress must streamline the licensing process by establishing FERC as the lead agency, giving it the authority to set and enforce schedules for the issuance of all resource agency authorizations and studies, and ensure any “mandatory conditions” are directly relevant to the project,” APPA argued.

Federal Tax Incentives

APPA said that another significant obstacle to the growth and retention of non-federal hydropower capacity is insufficient federal tax incentives on par with those available to other clean energy resources.

APPA noted that it strongly supports legislation introduced by Senators Maria Cantwell (D-WA) and Lisa Murkowski (R-AK), the Maintaining and Enhancing Hydroelectric and River Restoration Act of 2021 (S. 2306), that seeks to address this issue.

The bill would create a 30 percent tax credit to support upgrades at existing hydroelectric dams for qualified dam safety, environmental, and grid resilience improvements. “Critically, this credit would be available as a direct payment to public power utilities,” APPA said.

This provision is also included in a bill introduced by Representative Annie Kuster (D-NH), H.R. 4375, the Twenty-First Century Dams Act.

“It is critical that this provision be included in any energy tax credit legislation that may be considered this Congress,” the public power trade group said.

“Uncommon Dialogue” Effort

While APPA was not directly involved with the “Uncommon Dialogue” effort lead by the National Hydropower Association and a number of environmental and tribal organizations, it noted that many of APPA’s members are also members of the National Hydropower Association and were engaged as the proposal developed.

While APPA continues to believe that the hydropower licensing process requires more comprehensive reform along the lines of what was included in H.R. 3043 in 2017, “we appreciate the incremental changes included in the group’s recently (April 2022) released licensing reform proposals. We are particularly supportive of the proposed requirement that mandatory conditions under section 4(e) of the FPA be reasonably related to project effects on federal lands.” 

 With respect to other proposals put forth in by the Uncommon Dialogue group and associated legislation regarding dam removal, APPA said it opposes efforts to remove productive dams that provide, or have the potential to provide, clean and economic hydropower generation.

“Furthermore, proposals to appropriate funding for the Corps, Reclamation, and any other federal agencies for ‘dam related activities’ must include statutory text specifying that this funding cannot be incorporated into the rates paid by federal hydropower customers,” it said.

Federal Hydropower

APPA also said that federal hydropower and the Power Marketing Administrations are critical, though often overlooked, elements of the nation’s power supply.

APPA supports the continued existence and federal ownership of the PMAs and the sale of federally generated hydropower at cost-based rates and “strongly opposes any efforts to disproportionately assign costs to federal hydropower users for which they receive no additional benefits.”

National Hydropower Association

In his testimony at the hearing, the National Hydropower Association’s Woolf said that new and existing hydropower “is at risk due in part to the byzantine licensing and relicensing system.”

He said that the country is at the crest of a wave of hydropower licensing. “At the same time, relicensing takes 7.6 years to complete on average and often takes much longer than a decade.”

A recent industry survey found than more than 40 percent of hydropower industry asset owners said that they were actively considering decommissioning a facility, Woolf noted. “Alarmingly, 58 percent of facilities have submitted license surrender applications to FERC since 2010 including 17 in just the last two years.”

Reform of the hydro licensing process is urgently needed, he said, noting that the National Hydropower Association supports the joint license reform package.

A summary of the proposed changes, as well as the proposed changes to the text of the Federal Power Act (FPA) itself, are available here.

MIT Report Explores Leveraging Storage As Part Of Emissions Reduction Efforts

May 19, 2022

by Peter Maloney
APPA News
May 19, 2022

A new report from Massachusetts Institute of Technology (MIT) explores pathways for using variable energy resources (VREs), such as wind and solar power, and energy storage to remove carbon dioxide emissions from electricity systems efficiently by 2050.

“Our study finds that energy storage can help VRE-dominated electricity systems balance electricity supply and demand while maintaining reliability in a cost-effective manner — that in turn can support the electrification of many end-use activities beyond the electricity sector,” Robert Armstrong, MIT Energy Initiative (MITEI) director, Chevron professor of chemical engineering and chair of the Future of Energy Storage study, said in a statement.

Because storage technologies will have the ability to substitute for or complement all aspects of a power system, including generation, transmission, and demand response, they will be critical to electricity system designers, operators, and regulators in the future, the report’s authors said, adding that the report is designed to help government, industry, and academia chart a path to developing and deploying electrical energy storage technologies as a way of encouraging electrification and decarbonization throughout the economy, while avoiding excessive or inequitable burdens.

The report focused on three regions of the United States – the Northeast, the Southeast, and Texas – using models to look out to 2050. The results indicated that the deployment of long-duration energy storage technologies would have the greatest impact on electricity system decarbonization when natural gas generation without carbon capture and storage technology is not an option. Generally, the authors said, long-duration energy storage when optimally deployed substitutes for natural gas capacity, increases the value of variable renewable generation, and produces moderate reductions in system average electricity cost.

The report identified four categories of long-duration energy storage, redox flow batteries, metal-air batteries, hydrogen storage, and thermal storage, and said the long-duration technologies win out in the long term over lithium-ion batteries because they have lower energy capacity costs and lower round-trip efficiencies.

The authors did, however, say that using hydrogen for energy storage would likely depend on the extent to which hydrogen is used in the overall economy and its broad use “will be driven by future costs of hydrogen production, transportation, and storage — and by the pace of innovation in hydrogen end-use applications.”

The study also predicted that the distribution of hourly wholesale prices or the hourly marginal value of energy will change in deeply decarbonized power systems with many more hours of very low prices and more hours of high prices compared with current wholesale market prices, which could increase challenges for financing future investments in grid assets, including storage. “This issue impacts all resources and underscores the need for thoughtful electricity market reforms and retail rate design to encourage efficient economy-wide decarbonization,” the authors said.

The authors recommended the adoption of retail pricing and retail load management options that reward all consumers for shifting electricity use away from times when high wholesale prices indicate scarcity, to times when low wholesale prices signal abundance.

The MITEI report also said that many existing power plants that are being shut down and otherwise might be abandoned could be converted to energy storage facilities by replacing fossil fuel boilers with thermal storage and new steam generators using commercially available technologies.

Department of Energy Seeks Feedback On Long Duration Energy Storage

May 16, 2022

by Paul Ciampoli
APPA News  Director
May 16, 2022

The U.S. Department of Energy (DOE) on May 12 issued a request for information (RFI) seeking input on the structure of a $505 million long duration energy storage initiative.

“The new Long Duration Energy Storage for Everyone, Everywhere Initiative, created by President Biden’s Bipartisan Infrastructure Law, will advance energy storage systems toward widespread commercial deployment by lowering the costs and increasing the duration of energy storage resources,” DOE said.

The initiative, administered through DOE’s new Office of Clean Energy Demonstrations, will invest approximately $505 million over four years to validate grid-scale long duration energy storage technologies and enhance the capabilities of customers and communities to integrate grid storage more effectively.

DOE will implement three programs:

Under the overall Long Duration Energy Storage Initiative, DOE is also collaborating with the U.S. Department of Defense for long duration storage demonstrations at government facilities.

DOE’s Long Duration Storage Shot, launched in July 2021, sets a target of achieving a levelized cost of energy storage of $0.05/kWh, a 90% reduction from a 2020 baseline costs by 2030.

To meet this target, a wide range of energy storage technologies, including electrochemical, mechanical, thermal, flexible generation, flexible buildings, and power electronics, will need to be considered, well beyond the traditional lithium-ion batteries, DOE said.

In March, DOE’s Energy Storage for Social Equity Initiative selected 14 communities to receive technical assistance to leverage energy storage as a means of increasing resilience and long-term affordability.

The goal of the RFI is to solicit feedback from a wide range of stakeholders on DOE’s implementation strategy and eligibility requirements.

Comments must be received by 5:00 p.m. EDT on June 16, 2022, and can be submitted by emailing EnergyStorage41001RFI@ee.doe.gov.

A public webinar will be held to provide additional information.

Salt River Project Joins Coalition To Explore Zero-CO2 Strategies, Hydrogen Hubs

May 16, 2022

by Peter Maloney
APPA News
May 16, 2022

Salt River Project is a member of a new coalition formed in Arizona to explore strategies for achieving a carbon dioxide neutral economy in the state, including the creation of a regional clean hydrogen hub.

In addition to Salt River Project (SRP), the coalition includes Arizona Public Service, Tucson Electric Power, and Southwest Gas, as well as Arizona State University, the University of Arizona, and Northern Arizona University.

Together, the coalition members aim to develop a statewide strategy for “deep decarbonization – approaching carbon neutrality for the whole economy.” The coalition also aims to find solutions that help address climate change and sustain Arizona’s economy in a carbon-neutral future.

“This challenge is bigger than any one company or industry. SRP appreciates the support and vision of this diverse set of partners willing to roll up their sleeves, work together and find solutions to become a low-net-carbon Arizona,” Mike Hummel, CEO and general manager of SRP, said in a statement.

In a first step toward achieving its goals, the coalition has established the Center for an Arizona Carbon-Neutral Economy in the Julie Ann Wrigley Global Futures Laboratory on Arizona State University’s Tempe campus where the coalition members aim to begin planning for a regional clean hydrogen hub. While not yet fully defined, the clean hydrogen hub would include hydrogen producers, consumers, and a connected infrastructure.

Used as a fuel, hydrogen releases water, not carbon dioxide as fossil fuels do, so if renewable resources can be used to create clean hydrogen, which can then be stored for use at a later time.

The coalition said it would seek funding for the project under the Infrastructure Investment and Jobs Act that was passed into law in November 20221 and established program guidance and funding for regional clean hydrogen hubs.

In February, the Department of Energy announced two requests for information to collect feedback from stakeholders to inform the implementation and design of the infrastructure law’s Regional Hydrogen Hub and the Electrolysis and Clean Hydrogen Manufacturing and Recycling Programs.

“Hydrogen is a sustainable energy option we are excited to further explore with our industry and research-focused peers in this collaborative coalition,” Kelly Barr, chief strategy, corporate services and sustainability executive at SRP, said in a statement. “It could likely play a significant role in transitioning coal communities to a new economic way of life, while also supporting the grid with clean energy, which are vital initiatives for SRP, Arizona and the entire U.S.”

In March, the governors of Colorado, New Mexico, Utah and Wyoming signed a memorandum of understanding for the development of regional clean hydrogen hubs and to compete jointly for a portion of the $8 billion allocated for hydrogen hubs under the infrastructure law.

Also in March, New York State, Connecticut, Massachusetts, and New Jersey formed a coalition to develop a proposal to become one of at least four regional clean energy hydrogen hubs as designated by the infrastructure act.

APPA’s Ursula Schryver Highlights Local Control As Key Benefit Of Public Power

May 15, 2022

by Paul Ciampoli
APPA News Director
May 15, 2022

Local control over decision making in areas such as renewable energy or reliability offers a key advantage for public power communities, Ursula Schryver, Vice-President of Strategic Member Engagement & Education at the American Public Power Association (APPA), said during a recent event related to public power.

Schryver was joined in the discussion by Maine State Rep. Seth Berry and Darren Springer, General Manager for Vermont’s Burlington Electric Department.

The three participated in a virtual event on public power around the country and lessons learned for Ann Arbor, Mich., whose City Council earlier this year unanimously adopted a resolution initiating a feasibility study for a public power utility.

Schryver said that local decision making “is the overarching tenet of public power.” She noted that communities with public power have local control over “the decisions that they make, how the utility is run, the utility’s priorities, and so that allows the city and the community to set its own priorities,” whether that’s keeping rates low, investing in system upgrades or adding renewable energy to their portfolio.

“More and more, we’re seeing communities that are pursuing the public power option” because of an interest in renewable energy, she said.

At other times, communities have pursued the public power option for other reasons, such as reliability or rates, Schryver noted.

While renewable energy may be the driving force now for communities to pursue public power, “twenty years down the road it may be some other issue that your community is interested in but having the local utility with local governance allows you to” make changes and address the issues that are important to the community, she said.

Schryver also said that public power utilities are in a solid position to address the needs and challenges of the 21st Century.

She said that there a number of public power utilities across the U.S. that are “great examples of utilities that are doing innovative things.”

Public power utilities address the issues that are of importance to their communities and “they have the ability to adapt and change,” she said.

Berry, who has been a key advocate for bringing public power to Maine, said that public power is “a superior business model” if a community wants to achieve 100 percent renewable energy supplies.

He pointed out that two California public power utilities – SMUD and the Los Angeles Department of Water and Power – are “leading in the race to one hundred percent renewables.”

In Maine, a group called Our Power is working to create a statewide, consumer-owned utility.

Meanwhile, Springer provided an overview of Burlington Electric Department and detailed the utility’s key initiatives that it is pursuing.

Among other things, Springer discussed the City of Burlington’s net zero energy by 2030 goal and provided details on a $20 million net zero energy revenue bond. The bond will allow Burlington Electric Department to continue and expand green stimulus incentives that have helped Burlington residents switch to electric vehicles (EVs) and cold-climate heat pumps.

Online Tool Allows Users To Estimate Economic Impact Of EV Charging Stations

May 14, 2022

by Paul Ciampoli
APPA News Director
May 14, 2022

Scientists at the U.S. Department of Energy’s (DOE) Argonne National Laboratory recently launched an online tool that allows users to quickly estimate the economic impacts associated with the development, construction, and operation of electric vehicle charging stations, also called electric vehicle supply equipment (EVSE).

The impacts range from job creation to ripple-effect economic activity, such as local spending.

The tool, referred to as JOBS EVSE 1.0, permits users to estimate economic impacts for individual states, regions, or the United States as a whole.

The tool contains default input values, but users can override default data with their own data for more project-specific results.

Although it focuses on charging stations and the infrastructure immediately upstream from them, it also considers the entire energy supply chain in calculating impacts.

Impacts also include recurring expenditures for electricity, network and data fees, revenues, operating and maintenance and administration, as well as potential revenues and access fees.

JOBS EVSE 1.0 was developed with funding from DOE’s Vehicle Technologies Office.

To view a webinar about the tool, go to https://​cleanci​ties​.ener​gy​.gov/​w​e​b​i​n​a​r​s​/​#​28469.

Public Power Utilities Make Progress In Connecting Navajo Nation Families To Grid

May 14, 2022

by Paul Ciampoli
APPA News Director
May 14, 2022

Public power utility crews are making significant progress in their efforts to extend electricity to Navajo homes through Light Up Navajo III (LUN III), a joint effort between the American Public Power Association (APPA) and the Navajo Tribal Utility Authority (NTUA).

The LUN III initiative began on April 3, 2022 and will last for 11 weeks.

NTUA will be welcoming workers from public power utilities and organizations from 11 states, including Arkansas, Arizona, Delaware, California, Connecticut, North Carolina, New Mexico, Ohio, Washington, Texas, and Utah.

One of the public power utilities participating in LUN III is Arizona public power utility Salt River Project (SRP).

SRP on May 11 reported that its linemen have successfully connected more than 50 Navajo families to electric service despite rough terrain, high winds, snow and mud in unfamiliar land. In all, 56 families on Arizona’s Navajo Nation now have electricity powering their homes for the very first time, SRP reported.

The SRP linemen took four weeks of up to 16-hour workdays during their phase of the project.

“The first home we connected was the most touching for me. It was a mom who was living in a trailer with her children, and they had no power or running water. They had gotten sick with COVID-19 and had to quarantine at home. They were excited (to get power) and telling us how tough it had been the last few months,” said Art Peralta, SRP construction crew foreman, who resides in Mesa. “It’s very rewarding. I’ve never done anything like this, and it means a lot. It’s life changing and brings more meaning to our job.”

The SRP line crews returned home on May 8 after working on the Navajo Nation in northeastern Arizona since April 2.

During SRP’s participation in the month-long humanitarian effort, line crews constructed about 12 miles of distribution lines. SRP crews also set 193 poles, strung 13 miles of overhead wire and worked 4,500 hours of donated man-hours. It marks the second time SRP line workers, based out of the Tempe Service Center, volunteered to participate in Light Up Navajo.

A total of 17 SRP employees participated in the project and SRP donated employee time, line trucks, digging equipment and a mechanic service truck.

“Light Up Navajo III is an initiative to bring power to all the residents on Navajo Nation. There are about 14,000 homes on the Navajo Nation that currently do not have electric service. The vision back in 2019 was to solicit neighboring utility support primarily from public power utilities like SRP to help build the infrastructure to serve the community,” said Wayne Wisdom, the senior director of Distribution Grid Services at SRP. “For generations, these families have been living on their own with the use of generators, kerosene lamps, or whatever they have.”

“There was a mother, daughter and her two kids in Tuba City and they were really excited to have power. The kids were excited to be able to entertain themselves without having to turn on a generator and to watch TV. It was nice to get to see that and use our skills to help out,” said Austin D’addabo, SRP trades helper.

“It’s given me a different outlook on the work we do,” added Peralta. “Sometimes we take it for granted because we do it every single day. But (on the Navajo Nation) it’s not normal for them. They get really excited and are very grateful to get power.”

Along with SRP, the following public power utilities participating in LUN III are:

Two investor-owned utilities are also participating in LUN III: Arizona Public Service and New Mexico’s PNM Resources.