The Federal Energy Regulatory Commission on Feb. 16 approved two new extreme cold weather reliability standards aimed at implementing key recommendations from a joint inquiry into 2021’s Winter Storm Uri to prevent a recurrence of the power outages affecting millions of people in Texas and the South Central U.S.

The reliability standards, proposed by the North American Electric Reliability Corporation in October 2022, contain new and revised requirements to advance reliability of the grid during extreme cold weather temperatures.

They include implementation of generator freeze protection measures, enhanced cold weather preparedness plans, identification of freeze-sensitive equipment in generators, corrective actions for when equipment freeze issues occur, annual training for generator maintenance and operations personnel, and procedures to improve the coordination of load reduction measures during a grid emergency.

While FERC approved the new extreme cold weather reliability standards, it also identified areas for improvement, and directed NERC to modify the extreme cold weather preparedness and operations reliability standard to address concerns related to applicability, ambiguity, a lack of objective measures and deadlines, and prolonged, indefinite compliance periods.

Also, along with the approval and directives for modifications, FERC directed NERC to collect and assess data over time to monitor and assess entities’ implementation of the new requirements.

The reliability standards FERC approved implement approximately half of the standards-related recommendations from the joint inquiry into the 2021 winter storm.

The remaining recommendations will be addressed in a second phase of NERC’s standards development, which is now under way.

In February 2021, Winter Storm Uri led to the largest controlled firm load shed event in U.S. history, with over 4.5 million people losing power. 

Shortly thereafter, the Commission, along with NERC and Regional Entities, initiated a joint staff inquiry into Winter Storm Uri that resulted in the issuance of a joint report in November of 2021.

The report included recommendations for reliability standard enhancements to improve extreme cold weather operations, preparedness, and coordination.

Douglas County Public Utility District in Washington State is moving ahead with the second phase of its green hydrogen project.

Specifically, Douglas County PUD Commissioners Ronald Skagen, Aaron Viebrock and Molly Simpson recently approved the purchase of a second 5-megawatt electrolyzer. Delivery of the second electrolyzer is expected to take 24 months.

Douglas PUD recently signed a contract with IMCO General Construction for phase one of its hydrogen production and fueling facility being built in Baker Flats. Site preparation, underground utilities and storage tank installation are complete at the site. Production of hydrogen is scheduled for June 2024.

The Baker Flats facility has capacity to accommodate up to 80 MW of green hydrogen production.

Douglas PUD said the additional hydrogen production capacity would create more opportunities for the utility to balance the integration of renewables resources, variable seasonal pricing, and fish water quality concerns at its Wells Hydroelectric Project. In addition, increased efficiencies will reduce generator unit maintenance costs, which translates to better rates and reliability for our customer owners, the utility said.

“There is a high demand for green hydrogen,” Gary Ivory, Douglas PUD general manager, said in a statement. “Our Wells Hydroelectric Project also positions us to take advantage of the state and federal incentives to advance green hydrogen opportunities in our region.”

Douglas PUD recently received a $5 million tax credit for equipment being installed at the hydrogen production facility as a result of an expansion of tax credits for hydrogen equipment.

“Douglas PUD is in a unique position to shape the policies being crafted around green hydrogen for the benefit of our customers,” Ron Skagen, Douglas PUD commission president, said in a statement. “We appreciate the legislatures’ support of the Pacific Northwest Hydrogen Associations hydrogen hub application.”

Douglas PUD serves 17,000 customer-owners with reliable power and internet service and owns an 840-MW hydroelectric project on the Columbia River.

The New York Power Authority on Feb. 16 released a report that recommends proven and innovative approaches on integrating dual-land use for agriculture and solar energy production. The report was funded through a $102,000 grant from the American Public Power Association’s Demonstration of Energy & Efficiency Developments program.

The study determined that a best practice agrivoltaic site ideally involves stakeholder collaboration, community education, policy incentives, site safety practices, and site-individualized crop selection and solar array design.

 Agrivoltaics is the simultaneous use of land for typical agricultural practices and photovoltaic power generation through the use of solar panels. Agrivoltaic systems are designed so that solar panels allow sufficient light to pass to ground crops while also capturing enough sunlight to generate electricity.

In March 2022, NYPA announced receipt of the DEED grant. The DEED program funds research, pilot projects and education to improve the operations and services of public power utilities.

NYPA collaborated with EPRI, an independent, non-profit energy research and development organization, to conduct research and publish the report.

Researchers who authored the new report examined how native vegetation, pollinators, low maintenance plants, agricultural crops as well as grazing livestock can coexist on the same parcel of land as a solar energy project. 

The study determined that leading agrivoltaic practices are those that promote the following:

• Collaboration between the farmer, solar developer, and the power purchaser early in the site selection process to mitigate concerns and establish protocols for the development and management of the solar site that work for the farmer’s needs.
• Educational programming that fosters a two-way dialogue between farmers and solar developers to create a mutually beneficial site.
• State-level incentive policies for co-location that makes site-selection more affordable for developers.
• The development of solar site safety practices that complement a partnering farmer’s crop rotation schedule to ensure that they can access the site to tend to their crops or herd.
• Continued research to identify site-specific crops and array design alterations to accommodate the selected crop where appropriate.

The research initiative is one of NYPA’s projects that support New York’s goal to generate 70 percent of the state’s electricity from renewables by 2030.

The commitment includes the installation of 6,000 megawatts of solar power by 2025. New York is on target to meet that goal, and by annually installing more than 400 MW per year since 2018, it reached a combined total capacity of 3.3 GW of solar generation at the end of 2021.

“With this report, the Power Authority has drafted a blueprint for sustainable land practices to help guide New York to a more resilient, carbon-free future,” said New York Power Authority Acting President and CEO Justin Driscoll. “This agrivoltaic study provides significant insights for NYPA and New York State as we collaboratively work to meet our nation-leading climate and clean energy goals.”

“This project proves the value of collaboration in research and development and shows how diverse organizations can work together to forge new paths,” said Paul Zummo, Director of Research & Development at the American Public Power Association.

NYPA completed an agrivoltaic system comprised of 250 solar panels at the State University of New York College of Agriculture and Technology at Cobleskill in partnership with the college and the New York State Energy Research and Development Authority in 2015.

In addition to the Power Authority’s efforts in agrivoltaics, New York State has established the Farmland Protection Working Group and the Agricultural Technical Working Group. The working groups are designed to ensure solar siting that is responsive to the needs of New York’s agricultural communities.

The report is available here. APPA held a webinar on Feb. 15 related to the report. A replay of the webinar is available to APPA members.

NYPA is a long-time DEED program partner and received $250,000 to fund two demonstration projects in 2021 — one that is analyzing the impact of ice on a hydropower plant and one testing an advanced technology that evaluates the health of high voltage assets in a substation.

Click here for additional details on the DEED program.

A new battery design shows promise to deliver longer duration with lower costs and safer materials, according to a new report from the Pacific Northwest National Laboratory.

The report, published this month in Energy Storage Materials, tested a small, coin shaped sodium-aluminum battery. Adena Power, supplied PNNL researchers with their patented solid-state, sodium-based electrolyte to test the battery’s performance.

“Our primary goal for this technology is to enable low-cost, daily shifting of solar energy into the electrical grid over a 10- to 24-hour period,” Vince Sprenkle, a PNNL battery technology expert, said in a statement.

The test showed that the new molten salt battery design has “the potential to charge and discharge much faster than other conventional high-temperature sodium batteries, operate at a lower temperature, and maintain an excellent energy storage capacity,”

Guosheng Li, a PNNL materials scientist and the principal investigator of the research, said in a statement. “We are getting similar performance with this new sodium-based chemistry at over 100 °C [212 °F] lower temperatures than commercially available high-temperature sodium battery technologies, while using a more Earth-abundant material.”

Because the new design operates at a lower temperature, it can be manufactured with inexpensive battery materials, instead of requiring more complex and expensive components and processes as in conventional high-temperature sodium batteries, David Reed, a PNNL battery expert and co-author of the study, said in a statement. The PNNL researchers estimated that a sodium-aluminum battery design could cost as little as $7.02 per kilowatt hour for the active materials.

The new sodium-based molten salt battery uses two distinct reactions. The PNNL team previously reported a neutral molten salt reaction. The new discovery shows the neutral molten salt can undergo a further reaction into an acidic molten salt that increases the battery’s capacity, the researchers found. Specifically, they reported that after 345 charge/discharge cycles at high current, the acidic reaction mechanism retained 82.8 percent of peak charge capacity.

The tests showed that new battery design could deliver up to 11 watt hours per kilogram (Wh/kg) of discharge energy. Lithium-ion batteries used in commercial electronics and electric vehicles typically deliver an energy density of about around 170–250 Wh/kg.

However, the new sodium-aluminum battery is inexpensive and easy to produce in the United States from much abundant materials, the PNNL researchers said. It uses sodium, which is relatively abundant, and aluminum wool, a manufacturing byproduct.

The new design is a variation on the sodium-metal halide battery that has been shown effective at commercial scale and is already commercially available, but with a significant change. “We have eliminated the need for nickel, a relatively scarce and expensive element, without sacrificing battery performance,” Li said. In addition, the aluminum cathode charges more quickly than nickel, which is “crucial to enable the longer discharge duration demonstrated in this work.”

State-of-the-art for grid energy storage using lithium-ion batteries is about four hours. The new design is “especially adept at short- to medium-term grid energy storage over 12 to 24 hours,” PNNL said.

The PNNL team is now focusing on further improvements to increase the discharge duration of the new battery design to improve its ability to work in coordination with renewable power sources.

“This research demonstrates that our sodium electrolyte works not only with our patented technology but also with a sodium-aluminum battery design,” Neil Kidner, a co-author of the study and president of Adena Power, said in a statement. “We look forward to continuing our partnership with the PNNL research team towards advancing sodium battery technology.”

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.

A broad coalition representing stakeholders in the distribution transformer supply chain is urging the Department of Energy to reconsider its intention to increase energy conservation standards for distribution transformers, as signaled in a recent Notice of Proposed Rulemaking issued by DOE.

The American Public Power Association and other members of the coalition made their request in a Feb. 15 letter to Secretary of Energy Jennifer Granholm.

“Since 2021, our organizations have been communicating with DOE regarding the severe and ongoing supply chain challenges that have prolonged and complicated distribution transformer production and availability,” the groups said in their letter.

“The inability to quickly manufacture and deliver these critical components threatens the ability of the electric sector to service current and planned housing markets, swiftly recover and restore service following natural disasters, and deliver the benefits of economy-wide electrification,” they told Granholm.

The groups pointed out that Granholm last June directed the Electricity Subsector Coordinating Council to establish a “Tiger Team” to examine the supply chain crisis. “It concluded that current transformer production is not meeting demand — demand that is expected to increase for the foreseeable future,” APPA and the other groups noted.

Moreover, both the electric and manufacturing sectors have raised awareness of the risks caused by lengthy lead-times in the production, procurement, and deployment of transformers. Under existing production output capabilities, manufacturers estimate the current order-cycle for most new distribution transformers to be longer than 16 months, the letter said.

In January, DOE issued a NOPR that would, through its various requirements, further exacerbate the supply chain situation, the groups said. The proposed rule would dictate that manufacturers increase the efficiency of distribution transformers by a mere tenth of a percentage point. DOE already mandates distribution transformers be manufactured to incredibly high efficiency standards, the groups noted.

“Our organizations agree that energy efficiency standards play an important role in reaching decarbonization benchmarks while transitioning our nation to a clean and increasingly electrified economy. However, as proposed, the rule would delay the realization of these benefits by worsening supply chain complications already well known to DOE.”

In addition, APPA and the other groups said that the proposed rule would require manufacturers to transition to a different type of steel, which is largely untested, less flexible, and more expensive.

“Further, the existing supply chain of this alternative steel is very limited and mostly foreign-sourced. This rule would impose unnecessary cost burdens and further delay the delivery of such critical products. Simply put, this DOE proposal does nothing to address, and is likely to exacerbate, the current distribution transformer shortage crisis,” the letter said.

“Given the unprecedented demand for distribution transformers, our organizations urge DOE to maintain the current efficiency levels required of these products. Getting these already highly efficient products into the market more quickly should be the highest priority and will result in the realization of electrification benefits much sooner — benefits that will far outweigh any gains achieved through a fractional percentage increase in efficiency.”

Other groups signing on to the letter were the Edison Electrical Institute, GridWise Alliance, Leading Builders of America, National Association of Home Builders, National Electrical Manufacturers Association and the National Rural Electric Cooperative Association.

Groups Say Department of Energy Proposal Raises Reliability, Affordability Questions

In recent related news, APPA and NRECA told the Department of Justice that reliability and affordability for U.S. electric utilities and their customers could be threatened under the DOE NOPR.

The DOE’s NOPR would transition almost the entire distribution transformer market in the U.S. to use amorphous steel cores, but there is only one domestic producer of amorphous steel cores today and that producer’s current output “is a mere fraction of what would be required to adequately meet the electric utilities’ demand,” the groups noted.

The U.S. Treasury Department, the U.S. Department of Energy and the Internal Revenue Service on Feb. 13 released details on a program included in the Inflation Reduction Act that offers a boost of up to 20 percentage points to the investment tax credit for solar and wind energy projects in low-income communities.

The notice released by the federal agencies outlines the program goals, including increasing clean energy facilities in low-income communities, encouraging new market participants, and benefitting individuals and communities that have experienced adverse environmental impacts or lacked economic opportunities.  

The program will allocate 1.8 gigawatts of capacity available in 2023 across four categories for solar and wind projects with maximum output of less than five megawatts.

The notice announces allocations for 2023: 700 MW for facilities located in low-income communities; 200 MW for facilities located on Tribal land; 200 MW for facilities serving federally-subsidized residential buildings, including housing supported by the Low-Income Housing Tax Credit and Section 8 of the Housing Act; and 700 MW for facilities where at least 50 percent of the financial benefits of the electricity produced go to households with incomes below 200 percent of the poverty line or below 80 percent of area median gross income.

The application process for the Low-Income Communities Bonus Credit program will open in 2023 in two phases.

Applications for facilities that are part of low-income residential buildings and those that benefit low-income households will be accepted first, with applications for other projects to follow. The guidance maintains Treasury and IRS discretion to reallocate excess capacity to oversubscribed categories, and any unallocated 2023 capacity will rollover to the following calendar year.

Future guidance will provide additional information about the application process and eligibility.

Qualifying Advanced Energy Project Credit

A second notice released by the agencies establishes the expanded Qualifying Advanced Energy Project Credit program under Section 48C of the Internal Revenue Code. This program renews and expands an investment tax credit initially included in the American Recovery and Reinvestment Act of 2009.

The program provides incentives for clean energy property manufacturing and recycling, industrial decarbonization, and critical materials processing, refining, and recycling. The notice provides a broad range of examples of projects eligible to apply for an investment tax credit of up to 30 percent, including manufacturing of fuel cells and components for geothermal electricity and hydropower, equipment for carbon capture, and critical minerals processing facilities.

The Inflation Reduction Act provided $10 billion in new funding for the Qualifying Advanced Energy Project Credit program. In the Inflation Reduction Act, Congress required that at least $4 billion be reserved for projects in communities with closed coal mines or retired coal-fired power plants.

The initial funding round outlined will include $4 billion, with about $1.6 billion reserved for projects in coal communities.

The application process for the Qualifying Advanced Energy Project Credit program will begin on May 31, 2023.

The Treasury Department and IRS will administer the programs, working in close collaboration with the Department of Energy.

The U.S. Department of Energy should ensure that its implementation of funds authorized in Section 40207 of the Infrastructure Investment and Jobs Act “advances a diverse portfolio of market-ready technologies that includes both lithium and non-lithium alternative battery chemistries,” a bipartisan group of Senators said in a recent letter to Secretary of Energy Jennifer Granholm.

To date, all programmatic funding awards for IIJA Section 40207(b) were for projects related to the lithium-ion battery supply chain, the lawmakers said in their Jan. 30 letter.

“We are pleased to see this funding awarded and recognize the importance of domestic lithium-ion batteries, especially in the transportation sector. However, going forward the Department should also seek to accelerate the deployment of domestic alternative battery manufacturing for grid-scale battery energy storage, in addition to lithium-ion technologies, in line with Congressional intent,” they wrote.

Signatories to the letter were Sen. Joe Manchin (D-WV), Chairman of the Senate Energy and Natural Resources Committee, Angus King (I-Maine), Jim Risch (R-Idaho), Shelley Capito (R-WV), and Sheldon Whitehouse (D-RI).

The lawmakers noted that according to the DOE’s recent report on supply chains for grid energy storage, ensuring more than one technology and different chemistries among the options for grid energy storage systems will increase the resiliency of the overall supply chain.

In December 2022, Congress provided additional clarity and direction to the DOE via report language expressing the desire for a wide array of battery chemistries.

Click here for a recent feature in Public Power Current that details how 2023 could prove to be a key inflection point for the emergence of alternative energy storage technologies.

Michigan public power utility Holland Board of Public Works continues to make progress on the construction of a new substation.

The East Point Substation will be the utility’s 10th substation and is projected to go online by June 30, 2023. It will be able to serve 80 megawatts of additional load.

Over the past four years, Holland BPW’s electric territory has experienced a substantial amount of meter growth in every customer category: residential, commercial, and industrial, noted Julie DeCook, Communications Manager at the utility.

She said that the biggest driver for building the new East Point substation is an expansion of the LG Energy Solution EV battery plant in Holland. The LG Energy Solution expansion is expected to increase Holland BPW’s annual energy needs by roughly 40%.

“On top of that, other companies are building new construction and expansions in the same area. Those additional companies are also increasing the need for electrical distribution capacity,” she said.

When asked if there have there been any supply chain challenges related to the substation project, DeCook said that while supply chain issues are present, “we try to navigate those challenges with forethought. We ordered specific equipment well in advance in order to keep the project on schedule. We expect to bring this substation online in Summer 2023.”

The U.S. microgrid market reached 10 gigawatts in the third quarter of 2022, with more than 7 GW in operation and the rest in planning or construction stages, according to a new analysis from Wood Mackenzie.

“In terms of customer segments, Commercial and Industrial leads the way with significant project development in industries such as retail (department stores) and manufacturing, which indicates a rise in demand for an uninterrupted electricity service,” said Elham Akhavan, senior research analyst at Wood Mackenzie. “The government sector takes second place, driven by the military’s resilience and decarbonization targets, followed closely by the residential and education sectors,” Akhavan added.   

The U.S. microgrid market has seen a 47% increase in solar and storage capacity in 2022 compared to 2017 levels. Moreover, Wood Mackenzie data shows that more than 175 solar- and solar-plus-storage microgrid projects have been in active development and were scheduled to come online by the end of 2022.

Akhavan said: “There’s been a significant shift in technology type, in particular the rise of solar and storage demand among microgrid customers, largely driven by corporate ESG goals. This has triggered an uptake of multi-distributed energy resource microgrids – known as advanced microgrids – which are used in cases where solar and storage alone are insufficient to mitigate long-duration outages. A fossil fuel generator, often sized to cover the entire site, acts as backup for the solar and storage to ensure uninterrupted service when the grid is down.”

The turnkey microgrid-as-a-service business model is projected to experience continued growth across various non-utility customer segments. The influx of diverse investors eager to finance long-term projects, often with ESG attributes, has led to the dominance of the microgrid-as-a-service model. Simultaneously, the industry is seeing a gradual shift away from end-user ownership, the consulting firm said.

According to Wood Mackenzie’s data, the percentage of microgrids owned by end-users dropped 31% from 2019 to Q3 2022, while the share of MaaS deals grew 25% over the same period.

While third-party financing in general is not a new model, microgrid-as-a-service “is evolving beyond PPA contracts, which often involves procurement from a single DER to an affordable solution for financing the construction, operation and maintenance of multiple DERs, tailored to the customer’s energy objectives,” Akhavan added.

Wood Mackenzie data shows that there are 28 states with utility microgrids, with approximately 35 megawatts expected to have come online in 2022. This implies total utility microgrid capacity of over 1.1 GW. 

“From a microgrid capacity perspective, if the market continues to develop at a rapid pace, we will see more than 20% growth in annual capacity installation across the US compared to last year,” Akhavan said

“The West coast, led by California, is growing substantially, with a strong pipeline due to go into operation by 2024. This is followed closely by the Southwest market which has expanded more than three times since 2019. Texas is the frontrunner, with two of the leading developers in the region, PowerSecure and Enchanted Rock, having installed all capacity so far in 2022,” Akhavan added.   

The industry has also seen growth in the Northeast where a range of competitive grant programs are supporting resilience projects for critical facilities. However, recovery from the COVID-19 slowdown is uneven across regions in the US. For example, the Southeast has yet to recover to pre-pandemic growth.

Switching to cost based or cost reflective utility rates would make heat pumps competitive with natural gas heating and speed electrification, according to a new report.

The report, Heat Pump-Friendly Cost-Based Rate Designs, was done by Brattle Group for the Energy Systems Integration Group, a nonprofit organization that marshals the expertise of the electric industry’s technical community to support grid transformation and energy systems integration and operation.

In the white paper, the Brattle analysts analyzed a proprietary dataset of natural gas and electricity usage for 80 single-family residential customers of a large investor-owned utility with relatively high electricity rates and cold winters.

The analysis showed that the operating cost gap was positive, that is, the cost of operating heat pumps was higher for all 80 customers under default electricity rates than the cost of using natural gas-fired heating systems.

Heat pumps are more efficient than natural gas-based heating systems and their costs are expected to decline over time, but right now heat pumps are often more expensive to install and operate, the report noted.

However, the analysis also showed that cost based rate designs can improve the economics of heat pumps by making electric heating bills lower than natural gas heating bills.

“Moving to one of the three alternative rates flips all 80 customers from a positive cost gap to a negative cost gap, in which energy costs for operating the heating equipment are lower post-electrification,” the authors wrote.

Under rate II, the first alternative rate studied – rate I was the default rate – the fixed charge component of a customer’s bill was increased and the volumetric charge was lowered. The result was a reduction in customer heating bills sufficient to turn the operating cost gap negative for all customers.

Switching to a time of use day/night structure (rate III) or a demand-based structure (rate IV) resulted in even larger negative operating cost gaps with rate IV showing the largest reductions in electric heating bills for the sample of 80 single-family residential customers, the report found.

“These results reflect the fact that all of the alternative rate designs are better aligned with the marginal cost of generating and delivering power, compared to the default residential rate design, which typically is not,” the authors said. “In many jurisdictions across the country, retail electricity prices are largely disconnected from the marginal costs.”

The authors also noted that there was a large variation both geographically and temporally. “To the extent that retail prices are above the short-run marginal costs because a large portion of the fixed costs of delivering power are also collected through volumetric rates, this creates a distortion in price signals and leads to suboptimal levels of electricity consumption and adoption of new customer sited technologies,” they said.

One of the unintended consequences of such default electric rates, the report found, is the slower adoption of heat pumps because the use of heat pumps increases total electricity consumption and, therefore, electricity bills, making the use of heat pumps uneconomic under typical volumetric default rate structures.

The authors noted, however, that as electric system conditions evolve, and summer-peaking systems become winter peaking systems with increasing levels of building electrification, rate structures may need to be refreshed if they are to continue to reflect actual costs.

While alternative rates can make adoption of heat pumps more economic for many customers, the report’s authors said it is important to note the implications of those rates for customers’ other electric loads.

For some of the customers in the sample, switching to time-of-use rates (rate III) would increase their electricity bills by about $200 per year even before any electrification, the report found. For some other customers, switching to one of the demand-based rates would reduce their bills by about $100 per year before electrification.

The report recommended that utilities develop screening tools to determine which customers might benefit from alternative rates and market those rates accordingly. The report also recommended that utilities develop data analytics tools to identify customers who may be getting close to replacing their heating systems and contact them before they make an investment decision.