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October 30, 2024

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NERC, Texas RE Examine Wind Turbine Inverter Issues

In a joint report released Wednesday, NERC and the Texas Reliability Entity shared the lessons learned from a disturbance to ERCOT’s wind generation fleet earlier this year.

The Panhandle Wind Disturbance report covers the events of March 22, when faults at two separate wind facilities in North Texas caused output to be reduced by 765 MW and 457 MW respectively. Neither fault qualified for reporting as a Category 1i event under NERC’s event analysis process, which in ERCOT requires the loss of at least 1.4 GW to earn the label. However, in light of the ERO Enterprise’s efforts to examine the impact of inverter-based resources on the bulk electric system, Texas RE suggested that NERC and ERCOT join it to review the disturbance.

On the morning of the event, issues had already been building on the system for hours: freezing rain, snowfall and high winds were observed early in the morning, and generator operators “reported wind turbine icing and high wind speed cutoffs.”

The faults occurred at 4:16 and 4:47 a.m. CT near Amarillo. The first was an A-B phase fault on a radial 345-kV generator tie line, and the second was a B-C phase fault on a nearby 345-kV transmission circuit. ERCOT attributed the second fault to “galloping conductors,” a condition that occurs when ice forms on transmission towers and conductors and catches the wind, lifting the conductors in a galloping or jumping motion.

ERCOT Wind Output (NERC) Content.jpgERCOT wind output during the disturbances | NERC

Both faults cleared normally in 3.38 and 2.88 cycles, respectively. Based on data from supervisory control and data acquisition systems, the first tripped 273 MW of wind generation, after which additional wind plants in the area unexpectedly reduced power output by a total of 492 MW; the same unexpected power reduction occurred after the second fault, with 457 MW lost in all.

As a result of the generation loss, system frequency also fell. In the first event frequency dropped from 60.01 Hz to 59.9 Hz; ERCOT tapped 524 MW of generation responsive reserve service (RRS) in response, and the system recovered to 59.998 Hz within three minutes. During the second event frequency fell to 59.942 Hz but recovered to “nominal values” within 30 seconds without the deployment of RRS or load resources.

Analysis of the events found that the greatest share of generation reduction in the first fault was consequential tripping of wind resources, accounting for 36% of reduction. However, the report noted that such loss is expected for this kind of event. The next biggest cause, at 18%, was plant controller interactions that restricted “the ability of the plant to return” to normal operating levels. Multiple inverters at one facility were tripped by AC overvoltage, making this the third-biggest issue.

By comparison, in the second fault plant controller interactions counted for 35% of voltage reductions, followed by dynamic active power reduction at 31%. AC overvoltage tripping was third, with 16% of the reduction.

Wind Plant Reduction Fault (NERC) Content.jpgCauses of wind plant reduction for fault 1 (left) and fault 2 | NERC

The report concluded with recommendations for multiple stakeholders. For FERC, the authors suggested “significant overhauls” to the “interconnection procedures and agreements administered” by the commission to address gaps relating to interconnection studies, model quality checks and commissioning testing. Noting that FERC in June issued a notice of proposed rulemaking on interconnection procedures, the report said that NERC plans to push such changes in comments on the NOPR.

The report also urges NERC to update its reliability standards to account for the known performance issues in inverter-based resources, in particular by implementing a performance-based generator ride-through standard. Finally, the authors recommended that ERCOT follow up with facility owners on corrective actions and conduct a detailed model quality review and validation effort.

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NERC’s SPIDER Group Warns of Modeling Difficulties for DERs

In a white paper released on Wednesday, NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group warned that traditional approaches to power system planning analysis may not be adequate for the spread of distributed energy resources like rooftop solar panels and battery energy storage systems.

NERC formed the SPIDER group in 2018 to study the effect of distributed solar and battery facilities on bulk electric system reliability. The move was inspired in part by incidents like 2016’s Blue Cut Fire in California, when a fault on a transmission line led to the loss of about 1.2 GW of solar generation. (See FERC Accepts New Inverter Standard.) The group’s work includes reliability guidelines related to DER forecasting and modeling practices, as well as the standard authorization request for Project 2022-02 (Modifications to TPL-001-5.1 and MOD-032-1). (See NERC RSTC Revisits Rejected Standards Projects.)

Wednesday’s white paper provides an overview of SPIDER’s “efforts to quantify and qualify the manner in which DERs are changing the system planning process”; some of the issues related to the representation of DERs in power system planning models; and the DER-related gaps in existing planning methods that new software can help to bridge. It was created in collaboration with “a range of industry participants … representing utilities, ISOs, consultants and OEMs [original equipment manufacturers],” along with software vendors.

SPIDER pointed out in the report that rooftop solar and battery systems were “viewed as a distribution system concern only” when first introduced to the grid; however, events like the Blue Cut Fire proved this assumption incorrect. Citing studies in areas like Hawaii and California, the paper asserted that utilities will need to expect “a number of impacts on the bulk electric system” from DERs and warned that existing planning tools are inadequate for accounting for their effects.

“Future power system studies will require software tools that can track a large number of distributed resources … while providing the ability to observe and adjust the output of these resources across the entire simulation,” the white paper said. “At the same time, the addition of new DER tracking capabilities will need to be balanced against the increase in complexity for the user and data fidelity requirements that they will cause.”

The paper also identified “seams” between different types of power system studies, most notably between transmission and distribution studies. Because DERs straddle both of these elements of the BES, it is no longer sufficient to study them in isolation, the report warned; for example, when DERs inject power into the grid, they can impact the voltage and current dynamics of the distribution system along with “changing power flows at the bulk transmission level.”

In the short term, power system planners can improve the ability of transmission and distribution software tools to share data, but even with this, DERs present a challenge that may be difficult for a single software tool to analyze. A longer-term solution can be provided by co-simulation tools that are currently in “earlier development stages” and that might be able to “describe the full behavior of the system” as a whole.

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Ohio Supreme Court Gives Go-ahead to Icebreaker Wind Farm

The Ohio Supreme Court this week removed a major legal obstacle to the construction of Icebreaker Wind, a demonstration wind farm in Lake Erie, 8 to 10 miles northwest of downtown Cleveland.

In a 6-1 decision, the court ruled that the Ohio Power Siting Board’s May 2020 approval of the project was proper, ending a two-year legal battle that capped at least a decade of effort by the Lake Erie Energy Development Co. (LEEDCo).

The project would be the first freshwater wind project in the U.S. and have to stand up to winter ice flows on Lake Erie. It had been approved by the Ohio Environmental Protection Agency, the U.S. Department of Energy, the Federal Aviation Administration, the U.S. Coast Guard, the U.S. Army Corps of Engineers, the U.S. Fish and Wildlife Service and the Ohio Department of Natural Resources before the PSB ruled on the issue. It had also won significant funding from DOE.

With six turbines on 4.2 acres of state-owned lake bottom, the project would have a total generating capacity of 20.7 MW. The city of Cleveland and Cuyahoga County had agreed to buy about a third of the output. The company must still find takers for the remainder. LEEDCo has also partnered in 2016 with a Norwegian wind developer experienced in offshore wind projects.

The PSB initially approved the project with the condition that LEEDCo turn off the turbines at night for up to 10 months of the year to avoid interfering with bird migration and bats. The company countered that it would not be able to attract or keep investors if it agreed to that provision, as overnight winds are generally more reliable for power production.

After months of negotiation in which LEEDCo committed to enhanced radar surveillance, a sophisticated new collision detection system and a commitment to shut down when or if birds began colliding, the siting board approved the project.

But two residents of an upscale lakeshore community near Cleveland appealed the approval. They argued that LEEDCo had not submitted sufficient evidence for the board to determine the impact of the turbines on birds and bats. The board, which by then had decided to require LEEDCo to report bird collisions, rejected the argument and two subsequent appeals of its decision.

Writing for the court’s 6-1 majority decision, Justice Jennifer Brunner explained that the board collected the necessary research to allow Icebreaker to begin construction, while also requiring more data before the company can operate the turbines.

“Rather than requiring Icebreaker to resolve those matters before issuing the certificate, the board determined that the conditions on its grant of the application were sufficient to protect birds and bats and to ensure that the facility represented the minimum adverse environmental impact,” Brunner wrote.

LEEDCo Board Chairman Ronn Richard, CEO of the Cleveland Foundation, said Ohio has no choice but to embrace the energy transition to meet the state’s power needs. He noted that Intel’s decision to build the world’s largest computer chip factory near Columbus includes a commitment to power 100% of its operations with renewable energy. Other companies in Northeast Ohio and throughout the state have also set ambitious renewable targets.

“We’re pleased with the ruling from the Ohio Supreme Court,” Richard said. “The Cleveland Foundation has supported Project Icebreaker from its inception because this is about more than clean energy; this is about a healthy economy and a healthy community. Project Icebreaker shows that Northeast Ohio — and the entire state of Ohio for that matter — is open for businesses.”

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School Buses Uniquely Suited to V2G Technology, CT Green Bank Says

The CT Green Bank told Connecticut regulators Thursday that they should look closely at vehicle-to-grid (V2G) technology for the state’s school bus fleet in their investigation of medium- and heavy-duty electric vehicle (M-HDEV) integration into the power grid.

“There is potential for electric school buses to play a role in reducing peak demand and increasing resiliency of our communities,” CT Green Bank CEO Bryan Garcia said during a Public Utilities Regulatory Authority hearing for the investigation (Docket 21-09-17).

But Garcia also urged regulators to be patient when considering technologies that affect school children.

“We wanted to note that when we think about electric school buses as resources, we need to crawl before we walk and walk before we run,” Garcia said.

In May, Gov. Ned Lamont signed a bill that sets deployment targets for zero-emission school buses of 100% by 2030 for environmental justice communities and 100% by 2040 for all communities.

“School buses, uniquely, have predictable charging locations and times, which can allow them to [support the grid] without negatively impacting their operating schedules and their use as a transit asset,” Sara Harari, associate director of innovation and special advisor to the president at CT Green Bank, said in hearing testimony.

Coordinating and deploying V2G technology for electric buses and other M-HDEVs would support the authority’s goals of integrating new transportation loads and distributed energy resources into the grid cost-effectively, according to Harari. It would simultaneously lower the cost of the state’s energy transition by delaying or avoiding infrastructure upgrades, she said.

The benefits of V2G for the grid would also come with challenges.

“For all M-HDEVs, including school buses, the additional [charge and discharge cycles] required to participate in V2G accelerates the degradation of the battery, thus shortening the useful life of the vehicle,” she said. The frequency of kilowatt hours discharged with V2G participation, she added, could also reduce the EV warranty coverage.

Realizing a V2G school bus fleet will require utilities to have a much better understanding of the temporal and locational needs of the grid, Harari said.

“The Green Bank is not aware of either of the Connecticut-based utilities having this capability today,” she said.

Garcia pointed to the authority’s recently established Innovative Energy Solutions program as the right place for the state’s utilities to test managed charging and discharging for electric school buses. PURA tasked the utilities with administering the program in collaboration with the authority and stakeholders to innovate within the electric sector to meet state climate goals.

In its order establishing the innovation program, PURA estimated that the utilities would issue the first program solicitation in January. Pilot projects chosen under the program will have a $5 million maximum potential award.

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Baker Signs Bill to Boost Clean Energy in Mass.

After a few days of wavering, Massachusetts Gov. Charlie Baker signed a compromise climate and clean energy bill sent to his desk by the state legislature.

The wide-ranging bill, a follow-up to last year’s legislation setting emissions targets, aims to act on those goals by reducing emissions in the state from generation, transportation, buildings and more, with a heavy focus on offshore wind.

The new law removes the price cap for wind developers, while also adding new tax incentives, grants and loans for the industry. And it will enable the state to work with other New England states and the federal government to procure transmission for offshore wind.

“The sweeping energy bill signed into law today showcases why Massachusetts continues to be a national leader in offshore wind development,” said John Begala, vice president of federal and state policy at the Business Network for Offshore Wind. “The procurement reforms and historic investments will help the state fully realize … economic and environmental benefits, leading to a stronger offshore wind industry with greater job creation, new economic activity, and a more reliable and affordable power sector.”

The law also takes on transportation emissions, banning the sale of new gas-powered vehicles after 2035, requiring the installation of new charging stations across the state and updating Massachusetts’ electric vehicle rebate to include more eligible vehicles. (See Mass. Legislators Reach Deal on Clean Energy Bill.)

The EV portions have excited advocacy groups like the Green Energy Consumers Alliance, as well as those in the private sector who are seeing growing business from the early days of the state’s EV boom.

In a recent interview with RTO Insider, Matthew Guarracino, the CEO of Lynnfield-based JM Electrical, said that his firm has been seeing more and more demand for charging infrastructure installations. The new law will only increase that, he said.

“The vehicles are one half of it, and the vehicles are great, but the challenge is getting the infrastructure put in the same places as the vehicles. The infrastructure is lagging a bit behind,” Guarracino said. “So it’s great to see the federal government and state putting money behind this to move along that infrastructure.”

One of the bill’s most controversial provisions, which almost led Baker to sink it, will let 10 communities in Massachusetts ban fossil fuel hookups in new construction, in an attempt to reduce emissions from buildings.

That section, along with the rest of the bill, has enthused environmental advocates.

“This bill is a big deal,” Ben Hellerstein, state director for Environment Massachusetts, said in a statement. “With this bill becoming law, leaders in Massachusetts of all political stripes are showing that states can take meaningful climate action. This bill gives me hope that we can work together to build a future where all of us can thrive. We’re thrilled for our commonwealth to play a key role in building a world powered by 100% clean energy.”

Baker had tried to make several significant amendments, including to weaken the fossil-free building pilot, in the waning hours of the legislative session. But lawmakers left most of them on the table and sent it back to the governor’s desk for a signature or veto.

The governor eventually signed, but not without regrets.

“Because the legislature rejected virtually every meaningful amendment I put forth, this bill does not have the same shared sense of purpose that all previous climate legislation embodied, which is unfortunate,” he wrote in a signing letter.

“We all know the commonwealth faces significant challenges in dealing with two existential threats: climate change, and housing supply and affordability. This bill does not move Massachusetts in the right direction on housing. And the process by which many provisions in this bill are implemented will determine if this bill will make significant progress toward our climate goals,” Baker continued.

Funding for parts of the bill is also still wrapped up in a separate piece of legislation that failed to make it past the legislative deadline, but key lawmakers say they’re confident it will come together in informal sessions over the coming weeks.

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SPP Restricts Board, RSC In-person Attendance

SPP said Tuesday that it is limiting attendance at its in-person Board of Directors, Members Committee and Regional State Committee meetings scheduled for October at its Little Rock, Ark., headquarters.

Citing a recent rise of COVID cases in Arkansas and the disease’s persistence, the grid operator said it will restrict access to “rostered members” of the groups and a “handful” of SPP support staff.

“We did not make this decision lightly,” SPP said in an email to stakeholders. “We want to protect the health of our stakeholders and mitigate risk for our staff working on campus. We will miss the opportunity to see some of you in person.”

The RTO said it will stream the meetings for its stakeholders, promising an “immersive experience for those who attend virtually.”

Arkansas’ COVID case count has grown to more than 900,000, about 30% of the state’s population. The average daily increase over a rolling seven-day period recently fell to 962, its lowest level since early July. Only about half of the state’s residents are vaccinated.

The in-person meeting, although lighter in numbers, will be the groups’ second since January 2020. They last met together in Dallas in April.

Under SPP’s new meeting schedule, the board and RSC will alternate in-person and virtual meetings with the Markets and Operations Policy Committee and Strategic Planning Committee each quarter. The two committees met in Denver in July; they are scheduled to next meet in-person this January in Oklahoma City.

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DOE Previews New Federal Funding for Energy Storage Demo Projects

The Biden administration’s goal that the U.S. economy achieve net-zero carbon emissions by 2050 will require an investment of $300 billion a year until 2050, or $10 trillion in total, the U.S. Department of Energy estimates, including $21.5 billion to support large-scale clean energy demonstration projects.

Effectively allocating the $355 million in initial funding, authorized by last year’s Infrastructure Investment and Jobs Act, is the task now facing DOE, Katrina Pielli, senior policy adviser at the department’s Office of Energy Efficiency and Renewable Energy, said during a webinar Tuesday presented by the Clean Energy States Alliance with the DOE and the Sandia National Laboratories. The session drew several hundred spectators.

The department is taking time to develop “front-end planning” to help the industry develop storage projects that will be able to meet congressional expectation, Pielli said, adding that it is currently estimating it will begin accepting applications later this quarter.

“We’re maintaining a risk-balanced, defensible portfolio of investments. And what this means is that we will be reviewing project applications to ensure those selected for these demonstrations are viable at scale and they’re replicable. We want to scale down risk so we can scale up the clean energy technology deployment,” she said.

The agency will be making awards with 50-50 cost-sharing agreements, she added. “We’ll take early steps to set up these demonstrations, and our industry partners will assist with the steps that lead to commercialization and deployment,” she explained.

The law requires DOE to focus on rural areas with populations of less than 10,000, disadvantaged urban areas and former mining sites for potential projects.

“Congress did direct us to prioritize job creation, greenhouse gas emission reduction and the economic benefits for host communities. Here again, we’re working closely with our National Labs to understand the technical, regulatory and economic challenges associated with clean energy development on mined land,” Pielli said.

Dan Borneo, an engineering project leader at Sandia, said the goal is to reduce storage costs by 90% compared to the baseline cost for lithium-ion storage in 2020, to 5 cents/kWh, he said.

“For all the different storage technologies that are out there that could be used for grid storage, none of them currently meet a 5-cents/kWh levelized cost of storage. None of the technologies are there yet, which is why we need more investment and more demonstrations at scale,” he said.

“We are looking at targeting technologies in that realm with easy demonstration, all the way through more mature technologies that have already been proven, but may still need to be piloted in new or new regions that have not yet seen storage.”

Borneo said the lab will be funding demonstration storage programs for DOE and the Defense Department. “We’re looking at reasonably small behind-the-meter systems that can prove long-duration energy storage for a specific resilience application.”

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Hearing Shows Solar Conflict in Sun-soaked Eastern Wash.

A proposed massive solar farm is stirring controversy in southeastern Washington, pitting farmers and unions against local officials and the region’s Republican Party, while another similar project looms on the horizon.

Both projects are in the northwest corner of Benton County, just a few miles from four similar solar projects in neighboring Yakima County. All six are proposed for the same chunk of desert-like steppe habitat in the Yakima River Valley that crosses the line between the two counties. 

Benton County is home to the highly contaminated Hanford Nuclear Reservation, which is surrounded by pristine buffer zones, including Rattlesnake Ridge along the site’s western borders. The two Benton County solar farms are to be located west and southwest of the ridge on private farming and grazing areas.

On Monday, Washington’s Energy Facility Site Evaluation Council (EFSEC) held a public hearing in Pasco on a proposal by Innergex Renewable Energy to build the 470-MW Wautoma Solar Project just east of the Benton County line.

In Washington, an energy project developer has the choice of getting project approval from the state through EFSEC or from the host county. Innergex opted to go through EFSEC. 

Monday’s hearing turned out support from farmers in the immediate area and construction unions, and opposition from Benton County’s government and Republican Party.   

Québec-based Innergex is seeking to build the Wautoma project on 3,000 acres of sagebrush, of which less than 1% is being farmed. The project, which would include batteries capable of storing power for four hours, would be sited next to a major transmission line and is 30 to 40 miles from the nearest towns and cities. 

Laura O’Neill, Innergex senior environmental coordinator, said farm owners in the area are interested in the project and that the proposed site avoids environmentally sensitive lands. Western Hanford and the area west of the reservation are home to hundreds of elk, and the project’s fence would include openings for large animals to pass through.

Construction is scheduled to begin in the first quarter of 2024 and be completed by the third quarter of 2025. O’Neill said the project’s timetable and size could easily change during the design phase. 

‘Visual Pollution’

During Monday’s hearing, three members of the Robert family, which owns the 3,000 acres of primarily grazing land, lobbied EFSEC to support the Innergex proposal. Maya Robert said agricultural economics has been adversely affecting their ranching. “Solar power will help us make productive use of unproductive land,” she said.

Her uncle Robin Robert said roughly 800 sheep can share the land with the solar farm, with the animals using the panels for shade, making the project the Washington’s third proposal to develop agrivoltaics, the simultaneous use of solar panels with grazing or farming.

Stan Isley, representing the Yakima Valley Audubon Society, gave conditional support to the proposal, saying the developers must be careful of potential harmful effects to the wildlife and environment in that region.  Brendan Mercer, a neighboring grower of wine grapes, wanted to make sure the proposal’s effects on well water are studied and voiced concern about the impact of intense sunlight reflecting off panels on light-sensitive grapes.

“This proposal creates jobs and helps farmers. This is a very remote area,” said Stan Gasper, a Benton County resident. Four union leaders and members supported the project because its construction would employ hundreds, although only three to five permanent staff members would be needed after construction.

A woman representing the Benton County Republican Party opposed the project. “If you see a bunch of windmills and a bunch of solar panels, that’s visual pollution,” she said. There is an unrelated major wind and solar project several miles to the southeast within sight of the heavily populated Tri-Cities, which has sparked opposition because many residents don’t want to look at the wind turbines on their landscape.

Benton County resident George Penn opposed the Innergex project for visual reasons, arguing solar panels should be set up solely on the Hanford site, which is partially off-limits to the public. Area resident Lorre Gettre said farmers don’t always know the consequences of putting solar farms on their lands and voiced fears about the storage batteries leaking.

The Innergex site is on land zoned for agriculture. Last December, the Benton County Board of Commissioners — which vehemently opposes the wind and solar project south of the Tri-Cities — passed a law prohibiting large solar projects on agricultural lands. But Innergex argued Monday that the project is still consistent with Benton County’s comprehensive growth management plan.

Other Projects Loom

Meanwhile, a second solar farm is now in play for western Benton County.

Florida-based renewable energy company BrightNight confirmed to NetZero Insider Monday that it plans to build a 500-MW solar farm just south of Rattlesnake Ridge.  

The Hop Hill Solar project would be built on 17 square miles of cattle- and sheep-grazing land with the panels to cover about 30% of the site. The rest will be kept as grazing land, including the shady areas beneath the panels located eight to 10 feet above the ground, said Meribeth Sawchuk, BrightNight vice president of communications. While BrightNight has several projects on the drawing board across the nation, it has not yet completed any, she said.

No timetable has been set for the project. Unlike Innergex, BrightNight, plans to get approvals for its project from both the Benton County government and EFSEC. This will be the first renewable energy project in Washington to seek approval from both county and state governments. Swachuk said residents tend to be cautious about allowing solar farms on lands in their home counties. “It made more sense for us to coordinate with the county,” she said. 

All this is taking place as the Board of Yakima County Commissioners is considering whether to declare a moratorium on approving new solar farms as they examine the long-term impacts of this blossoming industry in the region.

Three of the four solar projects proposed for Yakima County are taking the EFSEC approval route, including two 80-MW solar farms by North Carolina-based Cypress Creek Renewables — High Top and Ostria — near the county’s eastern border.  

EFSEC is also considering whether it will approve at the 80-MW Goose Prairie solar farm by Seattle-based OneEnergy, while Yakima County is considering approval of the nearby 94-MW Black Rock project by California-based BayWa r.e. (See ‘Strength of Sunshine’ Brings Solar Projects to Wash. County.)

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DC Circuit Sends FERC Back to Drawing Board on MISO ROE

The long-running saga of the battle over MISO transmission owners’ return on equity continued Tuesday when the D.C. Circuit Court of Appeals vacated FERC’s 2020 order setting the rate at 10.02% (16-1325).

FERC must yet again determine what the just and reasonable ROE is in a case that has gone on for nearly a decade, with seven different commission chairs and three different presidential administrations (EL14-12, et al.).

In its ruling, the D.C. Circuit helpfully included a two-page-long chart (p.13-14) to show the three ROE figures FERC had set since November 2013, when MISO transmission customers complained that the then 12.38% rate was too high: 10.32% in 2016, 9.88% in 2019 and 10.02% in 2020. The fluctuating figures owed to the commission repeatedly changing the inputs for the complex formula that determines the ROE.

To get the latest figure, FERC used three different financial models — discounted cash flow (DCF), capital asset pricing (CAPM) and risk premium (RPM) — to determine a zone of reasonableness and set the ROE at its midpoint. (See FERC Ups MISO TO ROE, Reverses Stance on Models.) That reversed the commission’s previous stance against using the RPM just six months before, when it set the 9.88% ROE using only DCF and CAPM.

The court determined that was an arbitrary and capricious decision. It noted that in November 2019’s Opinion 569, FERC “spent several pages demonstrating the impressive extent of” the RPM’s deficiencies. But later in May 2020’s Opinion 569-A, “FERC changed its tune.”

“FERC is, of course, entitled to change its mind,” the D.C. Circuit said. “But to do so, it must provide a ‘reasoned explanation’ for its decision to disregard ‘facts and circumstances that’ justified its prior choice. Here, FERC failed to do that.”

In setting ROEs for private companies, like the MISO TOs, FERC essentially estimates what their stock price would be if they were publicly traded. Using the RPM, it estimates the cost of equity using the premium that investors would expect to earn on a stock investment over the return they would expect to earn on a bond investment.

In 2019, FERC argued, among many other things, that there was no evidence that investors used the RPM to make decisions and that the model takes into consideration previous ROEs, which may have been rendered unjust and unreasonable.

But in 2020, “FERC failed to adequately explain why it no longer mattered that investors don’t use this model,” the court said. “Instead, it simply noted that investors expect a premium on a stock investment over a bond investment, and that investors track the returns FERC allows. Both statements are true, but neither offers a persuasive reason to think that the risk premium model as FERC applied it here offers meaningful insight into investor behavior.”

FERC also failed to address the model’s circularity, the court said, merely stating that “all of the models contain some circularity.”

“That explanation doesn’t meaningfully engage with the ‘particularly direct and acute’ circularity problems presented by using old rates to set new ones,” the court said.

The D.C. Circuit did, however, dismiss the majority of the petitioners’ complaints about the 2020 order, including aspects of the DCF and CAPM and that the commission should have used the median of the zone of reasonableness, rather than the midpoint. The court found that these arguments conflicted with prior legal decisions on FERC’s ratemaking, but that the commission’s unjustified reversal on the RPM “is alone enough to make FERC’s rate orders arbitrary and capricious.”

FERC Chair Richard Glick, who had lambasted the then-Republican majority over the reversal, celebrated the court’s decision. “Reversing FERC on the risk premium model is a big win for consumers, helping make energy costs more affordable,” he tweeted.

With its order vacated, “FERC still lacks a judicially validated mechanism to set electric utility ROEs,” ClearView Energy Partners noted. “With the need to invest billions of dollars to upgrade the nation’s transmission system looming, FERC’s response will be closely watched by all stakeholders.”

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Akins Steps down as AEP President; Sloat to Become CEO

American Electric Power (NASDAQ:AEP) announced Wednesday that Nicholas Akins, CEO for the last 11 years, has resigned from his role as president of the company and been replaced by its current CFO, Julie Sloat.

In a brief press release, the Columbus-based utility said its board of directors would also promote Sloat as CEO beginning Jan. 1.

Sloat was named CFO in January 2021 after serving as a senior vice president of treasury and risk for two years and for nearly three years prior to that as president and COO of AEP Ohio.

AEP noted that Akins’ remaining time as CEO was part of the corporation’s “executive succession plan.” After Sloat takes over, he will become executive chair of the board, according to the release, and “will remain an executive and officer of the company.”

Akins has been president and CEO of AEP since 2011 and chairman of the board as well since 2014.

Nick Atkins (AEP) FI.jpgOutgoing AEP CEO Nicholas Akins | AEP

“Nick has transformed AEP during the 11 years that he has led the company. His focus on innovation, technology and modernization of the grid and AEP’s generation fleet is enabling clean, reliable and resilient energy to fuel growth in the communities that AEP serves,” Sara Martinez Tucker, lead director of the board, said in the release. “He also has built an open, collaborative culture that embraces diversity, equity and inclusion. AEP is fortunate that Nick has focused on developing a group of strong and capable leaders to ensure the company’s continued success.”

Akins praised Sloat as “an exceptional leader who has successfully led key strategic areas for the company. Her financial expertise and positive relationship with investors have been essential for the execution of our long-term strategy, enabling us to deliver strong earnings quarter after quarter while continuing to raise guidance and provide consistent dividend growth.”

“During her time as CFO, she has improved the financial performance of the company, and she also enhanced the performance and culture of AEP Ohio during the transition to competitive markets,” Tucker said. “The board is confident that she is the right person to lead AEP during this dynamic time for the industry and the company.”

Sloat initially joined AEP in 1999 as a credit risk analyst but left for 15 months in July 2008 to become vice president of investor relations job with Tween Brands, a clothing company. She returned to the utility in September 2009 as vice president of regulatory case management.

She has a bachelor’s degree in business administration with a double major in finance and economics and an MBA from Ohio State University. She completed the Nuclear Reactor Technology Program at the Massachusetts Institute of Technology.

“This is a time of tremendous change and opportunity for AEP as we invest in new energy technologies and infrastructure to provide clean and reliable energy to our 5.5 million customers,” Sloat said. “I’m honored to have the opportunity to lead an amazing team of nearly 17,000 employees.”