APPA, Others Ask Court To Reject Petitions, Uphold FERC Orders 872, 872-A
December 9, 2021
by Peter Maloney
APPA News
December 9, 2021
The American Public Power Association joined other power industry groups in filing a joint brief in the United States Court of Appeals for the Ninth Circuit, asking the court to deny petitions challenging Federal Energy Regulatory Commission (FERC) orders that revised FERC’s regulations implementing the Public Utility Regulatory Policies Act of 1978 (PURPA).
The petitions, filed by the Solar Energy Industries Association (SEIA) and a coalition of renewable energy and environmental groups, seek to vacate FERC orders 872 and 872-A.
The groups joining APPA in the Nov. 22 filing are the Edison Electric Institute, the National Rural Electric Cooperative Association, and the Large Public Power Council. APPA and the other trade groups are intervenors in the appeal in support of FERC, which filed a brief defending its orders in October 2021.
Under PURPA, electric utilities are required to purchase power produced by certain qualifying facilities (QFs) defined in the statute.The rates for these purchases are not to exceed the cost that a utility would have otherwise paid to generate or purchase the power – what FERC calls “avoided cost.” Avoided cost rates are generally set by state or local utility regulators.
Issued in July 2020, FERC’s Order No. 872, among other things, granted greater flexibility to state regulatory authorities in establishing avoided cost rates for QF purchases, both inside and outside of the organized electric markets, providing relief to utilities that have argued for years that some state-set avoided costs had become higher than the wholesale electric costs available to them. The rule also gave states the ability to require that energy rates, but not capacity rates, vary during the term of a QF contract.
Order 872 also modified the “one-mile rule” that FERC had long applied in determining whether a generating resource satisfies the 80 megawatt (MW) limit for one category of qualifying facilities – small power production QFs. The 80 MW limit encompasses all facilities located at the same site, and FERC’s one-mile rule provided that facilities located more than a mile apart were deemed to be located at separate sites. Some utilities had alleged that developers of renewable energy projects used the rule to avoid size limitations on QF projects by disaggregating large projects into smaller components and spacing the components to take advantage of the bright line one-mile rule.
Order 872 also reduced the size threshold that FERC applies in assessing whether a QF has nondiscriminatory access to organized power markets. Under amendments added to PURPA in 2005, utilities can ask to be relieved of the obligation to purchase power from QFs that have nondiscriminatory access to certain power markets. Prior to Order No. 872, FERC presumed that QFs smaller than20 megawatts (MW) lacked nondiscriminatory access to power markets, but FERC’s revised rules lowered the threshold to 5 MW for small power production QFs,, but not cogeneration, facilities.
FERC affirmed Order No. 872 in November 2020 in Order No. 872-A.
In their recent brief to the court APPA and its joint intervenors argued that FERC’s orders “were designed to continue encouraging certain power production addressed in PURPA, while ensuring that customers realize the benefits of the recent growth in renewable generation in the United States without paying above-market rates for that privilege.”
The petitioners “nonetheless cry foul, insisting that the Commission’s Orders will harm the environment and the renewables industry,” the intervenors wrote. “But in truth, their primary concern is preserving an obsolete regulatory framework that has morphed into an arrangement that consistently awards ‘qualifying facilities’ (‘QFs’) with above-market rates for the energy they produce, to the ultimate detriment of energy consumers,” they said.
The petitioners “paper over the fact that the practical effect of adopting their theories would be to extend them a further (decades-long) subsidy financed on the backs of utility customers, including those in rural areas and many who can scarcely afford that burden.”
In support of their position on FERC’s revisions to its avoided costs rate rules, the intervenors argued that FERC did not violate PURPA’s command to “encourage” QFs because the law does not call for the encouragement of QF development without constraint. Rather, the intervenors said, the “statute reflects a balancing of interests, including certain limits on the degree of such encouragement, such as the command that QF prices not exceed a utility’s avoided costs.”
“Petitioners wrongly read PURPA’s ‘encouragement’ clause as a one-way ratchet under which every aspect of every Commission action, taken in isolation, must prefer QF developers over other interests,” the intervenors wrote.
With respect to the “one-mile rule,” the intervenors argued that FERC “reasonably reformed” the rule “to curtail attempts by developers of oversized projects to garner unwarranted QF certification at the expense of consumers.” And in arguing that FERC’s reforms were not supported by the record, the “Petitioners ignore numerous examples of abuse provided by commenters and credited by the Commission,” the intervenors said.
The intervenors also supported FERC’s adjustment of the threshold for presumed nondiscriminatory access to wholesale electric markets from 20 MW to 5 MW, saying the agency’s decision was reasonable.
“Petitioners’ scattershot complaints about FERC’s rationale evince a misunderstanding of what the agency actually said and did,” the intervenors wrote. “In any event, QF developers who are unsatisfied with the revised rule are free to present evidence to overcome the 5 MW presumption.”
The intervenors also dismiss the petitioners’ challenge to FERC’s order as a violation of the National Environmental Policy Act (NEPA). APPA and the other intervenors disputed the petitioners’ standing to raise the NEPA claims, while also contending that the challengers’ NEPA arguments failed on the merits.
The intervenors argued that the petitioners’ claims are “meritless” and the court should not grant the requested relief. But if the court does find fault with FERC’s orders, it should not vacate the orders altogether. Rather, the intervenors argued, the court should “remand without vacatur because any such errors can be corrected on remand and because the disruptive consequences of vacatur would be severe.”
The intervenors also argued that the challenged provisions of Order 872 are “sufficiently separable that vacatur should be determined separately for each.” The court “should not invalidate important parts of the rule that no party challenged,” the intervenors wrote.
DOE Study Demonstrates Hydropower’s Ability To Support Grid Reliability
December 9, 2021
by Peter Maloney
APPA News
December 9, 2021
Hydropower can be a valuable resource in maintaining bulk power system reliability, according to a new report from the Department of Energy’s (DOE) HydroWIRES initiative.
HydroWIRES was launched in April 2019 by the DOE’s Water Power Technologies Office to understand and improve the contributions of hydropower and pumped storage hydropower (PSH) to reliability, resilience, and integration in the electric system.
The study analyzed the role of hydropower over a range of extreme events using a combination of historical data and simulation-based analysis.
The study looked at two main categories of events: the sudden loss of large generation assets and changes in net load due to extreme weather such as heat waves and cold snaps.
The scenarios used to evaluate hydropower’s role during extreme events were applied only to the Western Interconnection where hydropower constitutes between 20 and 25 percent of generation capacity.
The study found that hydropower could be critical in stabilizing the Western Interconnection after a sudden loss of generation. Historical data and simulation showed that hydropower is a major resource for inertial and governor response during extreme events. Specifically, the study found that hydropower facilities contribute between 30 and 60 percent of governor response to help stabilize system frequency after an outage.
Hydropower facilities also have significant reactive power capability that can help maintain voltage stability during extreme events, the study found. And while coal and nuclear plants can also provide reactive power, hydropower, like gas-fired plants, do not always operate at full power, enabling them to provide more reactive power support when needed. The study showed that hydropower is a major source of reactive power under all seasonal, loading, and water availability conditions.
The study also found that hydropower’s storage capability and dispatch flexibility are critical to ensuring system reliability during extreme weather events. Simulations of periods of extreme weather when wind and solar generation were significantly depressed, even though the impact on system load was not extreme, showed that hydropower resources were able to fill in energy and capacity gaps.
At least 40 percent of the nation’s hydropower resources are pumped storage and peaking or reservoir hydropower plants that can store water to produce electricity at times of greatest need. At least 18 percent of hydropower resources are run-of-river plants.
During a multi-day cold wave scenario, hydropower resources’ long-term storage capability was key in ameliorating the situation, the study found. In both historical and simulated scenarios, hydropower can contribute “significantly to grid reliability and resilience during extreme events,” the study found.
“The analyses in this study suggest that as the magnitude and frequency of extreme and stressful grid conditions increase, hydropower will continue to play a vital role in power system reliability and resilience,” the report’s authors concluded, adding, however, that “more work needs to be done to fully assess the role of hydropower under all potential combinations of future grid states and extreme events.”
Power Plant Coal Stockpiles Fall To Lowest Levels Since 1978: EIA
December 8, 2021
by Peter Maloney
APPA News
December 8, 2021
Coal stockpiles at electric power plants are at their lowest levels since 1978, according to the Energy Information Administration (EIA).
Stockpiled coal dropped to 80 million metric tons in September, their lowest level since March 1978 when stockpiles hit 77 million metric tons, according to EIA data.
The federal agency attributed the decline to two factors: less coal is needed as coal plants continue to retire and increased generation by coal plants over the summer reduced coal inventories.
In 2019, Moody’s Investors Service projected that utility demand for coal would decline significantly between 2020 and 2030, reducing coal-fired generation to as little as 11 percent of overall U.S. power generation, down from 27 percent in 2018.
Last summer, Moody’s predicted coal company earnings would fall by 50 percent in 2020 because of weak fundamentals and the effects the COVID-19 economic slowdown. The ratings agency also predicted a 25 percent drop in thermal coal production in 2020.
Coal plant operators typically stockpile more coal than they can burn in a month. Generating plants consume the most coal during the summer and winter months, causing stockpiles to drop to their lowest levels in the spring and fall and prompting generators to build back their reserves. However, physical delivery constraints in the supply chain can limit how quickly coal generators can increase their stockpiles, the EIA noted.
Nonetheless, coal stockpiles at generating plants, as measured by the “days to burn” metric, remain within recent historic parameters, the EIA said. “Because of less coal consumption as well as coal capacity retirements over the past three years, the days of burn of U.S. coal remain within the typical range, even though total stocks are low,” the EIA said.
For bituminous coal plants, which are mostly in the eastern United States, the average number of days of burn was 88 days in September, a slight increase from the 86 days of burn recorded by the EIA in August. The average number of days of burn for subbituminous units, which are mostly in the western United States, was 82 days in September 2021, the EIA noted.
The EIA, noting the long-term trend of declining coal consumption, also said many U.S. coal mines have begun to close. That trend, combined with supply chain disruptions, has created some concerns about the ability of coal-fired generators to replenish stockpiles to last through the winter.
Grid operators are, however, closely monitoring coal inventories. As an example, the EIA cited temporary changes taken by the PJM Interconnection regarding minimum inventory requirements to provide more flexibility for coal-fired generators.
Mass. Joint Action Agency To Participate In National Heat Pump Technology Challenge
December 8, 2021
by Vanessa Nikolic
APPA News
December 8, 2021
Massachusetts Municipal Wholesale Electric Company (MMWEC) has been selected by the U.S. Department of Energy (DOE) to participate in a technology demonstration program for next generation heat pumps in support of reaching net zero carbon emissions by 2050.
U.S. Secretary of Energy Jennifer Granholm announced DOE’s partnership with MMWEC on Dec. 3 at the Massachusetts Clean Energy Center’s Wind Turbine Technology Center in Boston.
DOE is also partnering with Energy New England (ENE), the largest municipal utilities cooperative in the Northeast, as well as Eversource, an investor-owned energy company, and National Grid, a multinational electricity and gas utility company.
ENE says its participation in the challenge ensures that its member municipal light plants have a voice during this point in the drive for carbon neutrality.
Granholm was joined by state officials, including Massachusetts Energy and Environmental Affairs Secretary Katie Theoharides, and Massachusetts Department of Energy Resources Commissioner Patrick Woodcock, to discuss the partnership, which is part of DOE’s Residential Cold Climate Heat Pump (CCHP) Technology Challenge.
Granholm mentioned that MMWEC would be part of a “consortium of those who will be getting us to the goals of efficiency and the deployment of heat pumps.”
The CCHP Challenge was announced by the Biden Administration in May and aims to reduce the carbon footprint of cold climate heating solutions by bettering the efficiency and affordability of new heat pumps. The challenge focuses on centrally-ducted, electric-only CCHPs that exceed efficiency performance at five degrees Fahrenheit or below.
MMWEC’s participation will include recruiting sites to install a prototype heat pump in a residential unit, fostering data collection, encouraging testing of grid interactivity features, and conducting customer satisfaction surveys.
MMWEC plans to work on developing customer incentives and pilot programs to promote the benefits of CCHP adoption. DOE will cover the costs related to equipment, installation, testing and evaluations of the pilot demonstrations.
Bill Bullock, sustainable energy policy and program senior manager at MMWEC, said MMWEC’s involvement in the challenge highlights its leadership in bringing technology opportunities to its member municipal utilities.
Established in 1976, MMWEC is a joint action agency that provides power supply, financial, risk management, and other services to municipal utilities in Massachusetts.
Voters Overwhelmingly Approve Net Zero Energy Revenue Bond For Burlington Electric Department
December 8, 2021
by Paul Ciampoli
APPA News Director
December 8, 2021
Voters in Burlington, Vermont, on Dec. 7 overwhelmingly approved a $20 million Net Zero Energy Revenue Bond for public power utility Burlington Electric Department with 70% of voters supporting the ballot measure.
Largely cost neutral to ratepayers, the Net Zero Energy Revenue 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, the utility noted.
The bond also will support grid updates for reliability, technology systems to better serve customers, and new EV charging stations.
“Through this bond, we’ll continue and expand our efforts to support our customers in switching from fossil fuels to clean technologies such as electric vehicles, cold-climate heat pumps, and more,” said Darren Springer, General Manager of Burlington Electric Department, in a statement.
The vote “not only moves us toward a Net Zero Energy future but also offers a compelling financing model for other public power utilities around the nation to consider as we all look to meet our climate commitments,” he said.
Additional information about the bond is available here.
Texas Utility Regulators Adopt Rule For Coordination Between Gas And Electric Industries
December 7, 2021
by APPA News
December 7, 2021
The Public Utility Commission of Texas (PUC) recently adopted a rule related to critical natural gas facilities that supply fuel to electric generators.
This joint effort with the Railroad Commission of Texas (RRC) will increase the coordination between the electric and gas industries during energy emergencies.
Based on legislation from the Texas Legislature, the new PUC rule creates a new designation for critical natural gas facilities that supply the majority of natural gas in Texas.
The rule also requires a critical natural gas facility to provide information to the utility from which it receives electric delivery service.
The electric utility must use this information to prioritize natural gas in energy emergencies. The PUC rule and corresponding RRC rule will be in effect this winter.
The rule adoption complements work being done to map the supply chain between the natural gas and electric industries, the PUC said.
Natural gas facilities have already registered critical status with their electric delivery utility in much greater numbers than last winter, it noted. “Now electric utilities can plan and respond much more accurately to keep natural gas facilities energized during an emergency,” the PUC said.
In February 2021, the Electric Reliability Council of Texas entered emergency conditions and initiated rotating outages in the state in the wake of an arctic blast.
Texas public power utilities took a number of actions to help protect customers financially in the wake of the arctic blast.
The American Public Power Association in November 2021 applauded the joint efforts of the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation (NERC), and NERC’s Regional Entities to analyze the February 2021 cold weather event in Texas and the South-Central U.S.
Federal Highway Administration Issues RFI For EV Grants Under Infrastructure Bill
December 7, 2021
by Peter Maloney
APPA News
December 7, 2021
The Federal Highway Administration, part of the federal Department of Transportation, has issued a Request for Information (RFI) for two new programs aimed at supporting the spread of electric vehicles.
The National Electric Vehicle Program or EV Charging Program will provide funding to states to deploy electric vehicle charging infrastructure and to establish an interconnected network to establish data collection, access and reliability.
The RFI also applies to the Charging and Fueling Infrastructure Program that aims to strategically deploy publicly accessible electric vehicle charging infrastructure and hydrogen, propane, and natural gas fueling infrastructure in designated alternative fuel corridors.
Both programs are being created as part of the Bipartisan Infrastructure Law (BIL), also known as the Infrastructure Investment and Jobs Act, that was signed into law in mid-November.
As a first step, the law directs the Department of Transportation (DOT) to coordinate and consult with the Department of Energy (DOE) to develop guidance for the two new programs.
DOT’s Federal Highway Administration (FHWA) posted the RFI in the Federal Register on Dec. 1 to invite public comments that will inform the development of guidance for the programs.
FHWA said it is particularly interested in comments suggesting ways that the guidance could promote equity in the development of electric vehicle charging infrastructure under the programs.
The new law “includes the largest dedicated bridge investment since the construction of the Interstate System, and the largest investment in electric vehicle charging infrastructure in history,” FHWA said in the RFI notice.
Specifically, FHWA said the BIL provides more than $350 billion over five fiscal years, from 2022 to 2026, for surface transportation programs, representing on an average annual basis nearly 29 percent more Federal-aid funding for highway programs and activities than under prior law and establishes more than a dozen new highway programs.
Among other things, the BIL apportions a total of $2.5 billion for “charging and fueling infrastructure grants” between fiscal years 2022 and 2026.
The RFI comment period will be open for 60 days.
The American Public Power Association is currently evaluating the RFI.
APPA Says FERC Should Avoid Mandating Top Down Transmission Planning Approaches
December 7, 2021
by Paul Ciampoli
APPA News Director
December 7, 2021
Any proposed rule in a Federal Energy Regulatory Commission (FERC) transmission-related proceeding should avoid mandating “top down” planning approaches, particularly those that identify resources based on speculative long-term assumptions about particular areas that have “potential” for resources to be developed, and/or that are based on long-range planning horizons, the American Public Power Association (APPA) recently argued.
APPA’s reply comments came in an advance notice of proposed rulemaking (ANOPR) proceeding at FERC. FERC issued the ANOPR in July 2021 to reform its transmission planning, cost allocation, and generator interconnection rules (Docket No. RM21-17).
APPA emphasized in its initial comments that its members’ experiences regarding transmission planning, generator interconnection, and cost allocation have varied by region and by transmission provider, and that diversity of perspectives is evident in the initial comments.
In the reply comments, the public power trade group said developing actionable transmission plans 10-20 years into the future on a uniform basis creates the risk of missing material changes in available resources, technology and load characteristics, as well as local and state laws imposing locational resource requirements, as commenters explained.
Although some commenters and technical conference panelists downplay the risk of overbuilding the grid or creating stranded transmission investment, the comments adequately substantiate these concerns, particularly as longer planning horizons are proposed, APPA said.
“Moreover, as Dr. David Patton observed at the November 15 Technical Conference, even if transmission does not go wholly unused, it may be economically inefficient from a consumer perspective if the assumptions on which transmission planning is based prove to be inaccurate,” APPA said. Patton serves as an independent market monitor for several regional grid operators.
“APPA recognizes that an overly conservative approach to transmission planning carries its own risks. But an effective bottom-up planning approach focused on the plans of LSEs [load-serving entities] is not overly conservative; it reflects a sufficiently broad and long-term view of future resources, while limiting transmission based on speculative future generation.”
LSE resource plans, “moreover, provide a basis for collaboration and input between transmission planners, transmission owners, LSEs, states, and other stakeholders to identify the most efficient and cost-effective transmission facilities to meet the needs driven by LSE resource plans.”
Such collaboration “is likely to result in greater consensus on appropriate transmission facilities and help reduce cost allocation disputes. By focusing on cost-effective transmission solutions that ensure that LSEs can serve their customers reliably and affordably, the transmission planning process is likely to consider the sort of long-term look at anticipated future generation that the Commission discusses in the ANOPR.”
If, contrary to APPA’s recommendations, the Commission facilitates a more speculative, top-down, long-range transmission planning process, it should consider measures that will diminish the risk to transmission customers, the group argued.
The initial comments and November 15 Technical Conference discussion also indicate support for regional flexibility in applying any revised transmission planning rules adopted by the Commission, APPA pointed out.
APPA urged the Commission to take a broader approach to regional flexibility. “Consistent with the path taken in Order No. 1000, the Commission could set more general guidelines about the need to plan for anticipated future generation and let particular planning regions propose compliance plans,” it said.
With respect to costs, APPA urged caution with respect to allocating costs based on ill-defined resilience benefits provided by new or upgraded transmission facilities.
“The Commission should not be prescriptive about how ‘resilience’ should be accounted for in the planning process, or how costs associated with promoting resilience should be allocated,” APPA said.
Regional planning processes that account for anticipated generation and utilize scenario planning as supported by APPA “should be able to identify particular risks or scenarios that stakeholders must guard against from a reliability and resilience perspective, which should also allow for reasonable identification of beneficiaries for purposes of allocating costs.”
Lincoln Electric System Annual Holiday Event With Local Zoo Fosters Customer Engagement
December 6, 2021
by Vanessa Nikolic
APPA News
December 6, 2021
Nebraska public power utility Lincoln Electric System (LES) partnered with the Lincoln Children’s Zoo (LCZ) to provide a holiday event for the community – Zoo Lights Powered by LES. The event offers an energy-efficient light show to the Lincoln community.
Zoo Lights Powered by LES was launched in 2019 and attracted 36,945 attendees. In 2021, the event continues to be LES’ main holiday engagement effort and remains one of the largest light shows in the area. The event is 100% lit by energy-efficient LED bulbs.
After LCZ transitioned from being open seasonally to open year-round, LES staff wanted to support the zoo’s new hours and approached LCZ staff with its idea to sponsor a community lighting event for the holidays. Both LES and LCZ saw the benefits of a community partnership.
The event continues to show many benefits to LES’ communications efforts from general brand awareness to customer outreach and community engagement. LES staff members volunteer by distributing handouts and answering customer questions during the event.
During the event’s inaugural year, the LES communications team developed a model gingerbread house to use as a platform to educate visitors about energy-efficient technologies, energy-saving tips, and rewards programs that LES offers. LES aims to expand its presence at the zoo and think of new ways to engage attendees.
LES says the event gives the utility a platform to speak to the community about electricity through the lens of holiday lights.
The “Zoo Lights” experience includes a 40-foot Christmas tree, over 30 lit animal silhouettes, holiday train rides, a tree canopy light walk, a 60-foot light tunnel, s’mores and hot chocolate stations, and more. Visitors can also take photos with two life-sized LES lineworker nutcrackers, Volts and Watts.
The event is open to the public through December 30 from 5:30 to 8:30 p.m. local time. For more information, visit LES.com/ZooLights.
Proceeds from Zoo Lights Powered by LES directly supports LCZ and its animals in the winter months.
To watch a preview of Zoo Lights Powered by LES, visit LES’ YouTube page.
Public Power Executives Detail Storage Project Benefits, Lessons Learned
December 6, 2021
by Paul Ciampoli
APPA News Director
December 6, 2021
Executives from public power utilities in North Carolina, Rhode Island and Minnesota recently detailed benefits and lessons learned from energy storage projects that their utilities have pursued.
The officials from Fayetteville Public Works Commission in North Carolina, Grand Rapids Public Utilities Commission in Minnesota and Rhode Island’s Pascoag Utility District, made their remarks during a session at the American Public Power Association’s (APPA) Public Power Forward Virtual Summit on Dec. 2.
Michael Kirkwood, General Manager at Pascoag Utility District, described a non-wires alternative project that “became a real money-saving option to avoid a large transmission expenditure that we were facing.” The project “fit in with some other reinforcements that we were doing on our system. The battery storage really made this possible and saved us a lot of money.”
Pascoag Utility District serves 4,900 customers in Pascoag and Harrisville, two villages in northwest Rhode Island. The PUD is connected to the outside world via two 5-mile 13.8 kV lines from investor-owned National Grid.
Peak load for the public power utility on the hottest summer days is about 13 megawatts. In 2018 and 2019, Pascoag Utility District started to reach the thermal limits of the main feeder line.
In 2019, Pascoag Utility District commissioned a system impact study that was completed by National Grid and offered several alternatives.
The public power utility determined that a non-wires alternative was the most cost-effective solution using a combination of substation enhancements and battery storage. The 3-megawatt/9-megawatt hour lithium-ion energy storage system is being built by Agilitas Energy.
The project has helped Pascoag Utility District avoid having to spend $6 million to $12 million “and if you look at that over 4,900 customers that’s a big nut to crack for a lot of years,” Kirkwood said.
The project will also increase reliability and reduce loading on the feeder lines, he noted.
Another panelist, Julie Kennedy, General Manager for Minnesota public power utility Grand Rapids Public Utilities, offered details on the utility’s solar plus battery storage project.
She noted that the project got its start in 2016 through a citizen initiative. A community solar project was initially considered, Kennedy said.
In late 2018, the public power utility presented a final report to its commission. “We said, you know what, it is a little bit difficult to make that subscription model work.” While the utility could have pursued that approach, “it really wasn’t meeting the hopes and desired outlook that we had had when we had our community outreach,” Kennedy said.
“What we did notice, though, was the parity in the pricing between solar only and the solar plus storage and so we started looking at those economics a little bit more closely and that is what caused us to add the energy storage.”
Along with US Solar and Grand Rapids Public Utilities, other parties involved in the project are Minnesota Power, a subsidiary of investor-owned Allete, the Itasca Clean Energy Team, and the City of Grand Rapids. US Solar is developing the two-megawatt solar array and one-megawatt/2.5-(megawatt?) hour energy storage battery on city-owned land near the Grand Rapids/Itasca County Airport.
Kennedy noted that installation of the solar panels at the site was completed in the fall. The storage battery “is, unfortunately, out at sea, still. We have been postponed with supply chain issues. Our next anticipated date is December 16. We are waiting to run our test energy. We are hopeful that it will be on site December 16,” with commissioning by the end of the year.
Meanwhile, Elaina Ball, CEO of Fayetteville Public Works Commission, detailed the utility’s community solar plus storage project.
“We were the first municipal community solar project in the state of North Carolina,” she noted. The project came online in 2019.
The 1-megawatt, 3,384 panel farm is located in northeast Cumberland County, adjacent to the utility’s Butler-Warner Generation Plant. In addition, the farm has 500-kilowatt battery storage. The battery is discharged 100% over two hours.
Ball said that the installed cost of the battery system itself “was a little over $900,000 and we expect about $5,500 in annual O&M costs just around the battery system and based on demand shaving that we’ve had, we expect our annual savings to be about $120,000. In a simple payback term, the battery is paying for itself in eight years.”
She said that “looking to the future, we want to add additional storage.” Ball noted that the utility’s wholesale contract allows for Fayetteville PWC to go up to 2 megawatts, “so we are in the process of adding another” one-and-a-half megawatts of storage.
“That’s really going to do two things. One, it’s going to be a four-hour discharge potential, which will give us much longer duration and give us an even better tool to hit that coincident peak window. But it’s also going to allow us to maximize our battery storage capacity. So we got our toe in the water, know how to operate this system” and the utility now wants to “push the capacity and we want to make sure that we’re getting as much value out of these resources as possible,” Ball said.
The utility is also studying additional community solar projects in its service territory. It is focused on looking at the economics of those projects, as well as “making sure that there’s customer demand to support additional resources in the community,” she said.
APPA Storage Tracker
APPA recently launched a Public Power Energy Storage Tracker, which is a resource for association members that summarizes energy storage projects undertaken by members that are currently online. The tracker is available here.