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November 8, 2024

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Robo Stepping down as NextEra’s CEO

Jim Robo said he is stepping down Tuesday after almost 10 years as CEO of NextEra Energy (NYSE:NEE), concluding what he characterized a “long-term succession process” he has undertaken with the board of directors during the last six years.

Jim-Robo-RTO-Insider-FI.jpgJim Robo is stepping down after 10 years as NextEra’s CEO. | © RTO Insider LLC

“It has been an honor and a privilege to serve as CEO. I’m as excited as I’ve ever been about the future prospects of NextEra Energy and NextEra Energy Partners,” Robo, 59, said during NextEra’s quarterly earnings conference call with financial analysts.

Saying part of a CEO’s legacy is the “new leader in the next-generation leadership team that follows,” Robo introduced as his successor John Ketchum, a 19-year NextEra veteran, CEO of NextEra Energy Resources (NEER) and president of NextEra Energy Partners.

Ketchum said he intends to remain “intensely focused” on delivering and building upon NextEra’s “long track record of success.”

“I believe there is no company better positioned to lead our country’s energy transformation than NextEra Energy,” he told analysts.

John Ketchum (NextEra Energy) Content.jpgJohn Ketchum | NextEra Energy

Under Robo’s guidance, NextEra has become the world’s largest generator of renewables, operating more than 17 GW of wind and solar energy. With a market cap of over $147 billion, it is bigger than any other utility in the world. However, efforts to acquire other utilities, including Hawaii Electric and Texas’ Oncor, fell short before it acquired Gulf Power from Southern Co. in 2018.

Robo joined NextEra in 2002, becoming CEO in July 2012. Since then, the company’s share price has gone from $17.08 to more than $300 in 2020, surpassing even ExxonMobil before a four-for-one stock split that October.

The company’s share price plunged on the news, dropping 4.5% from $81.87 when the market opened. Shares closed at $75.10, down $6.77 (8.3%).

Robo will serve as NextEra’s executive chairman during a brief transition period expected to end in April.

The Florida-based company announced several other leadership changes, effective March 1:

  • Eric Silagy, president and CEO of NextEra subsidiary Florida Power & Light, will become the utility’s chairman.
  • CFO Rebecca Kujawa was named president and CEO of NEER, succeeding Ketchum.
  • Kirk Crews, NEER’s vice president of business management, was named NextEra’s CFO, replacing Kujawa.

NextEra also reported its fourth-quarter and year-end earnings Tuesday. It said quarterly earnings were $1.2 billion ($0.61/share), compared to 2020’s fourth-quarter loss of $5 million. Analysts polled by FactSet had expected adjusted earnings of 39 cents/share; they came in at 41 cents.

For the year, earnings came in at $3.6 billion ($1.81/share), compared to $2.9 billion ($1.48/share) in 2020.

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Facebook Founder Donates $50M for Hawaii Climate Research

Facebook founder Mark Zuckerberg and his wife Dr. Priscilla Chan have pledged to donate $50 million to the University of Hawaii’s School of Ocean and Earth Science and Technology (SOEST), the university said last week.

The seven-year funding commitment will go to two departments within SOEST, the Hawaii Institute of Marine Biology (HIMB) and the Department of Oceanography, to fund research on climate change impacts and mitigation efforts in Hawaiian coastal waters.

“Hawaii has one of the richest marine ecosystems in the world, and having a deeper understanding of this ecosystem is the key to preserving and protecting it,” Zuckerberg and Chan said in a statement.

The funds will go to programs that focus on climate change impacts, coral reef restoration, ocean acidification prevention, conservation of large predators, resource management via indigenous means and community partnership growth, Marcie Grabowski, SOEST outreach coordinator, told NetZero Insider.

The research will be spearheaded by mature programs and initiatives that have already made significant contributions in ocean conservation and marine ecosystem knowledge, Grabowski said. “The gift is aimed at amplifying and expanding those efforts.”

More specifically, the research will:

  • more clearly define the extent of climate change impacts in Hawaiian coastal waters;
  • increase the accuracy of climate change forecasting for ocean conditions;
  • increase climate change resilience in coral reef ecosystems;
  • improve the understanding of shark behavior to help in their protection and conservation;
  • improve outreach efforts to inform the public and policy makers on research findings;
  • train the next generation of ocean scientists; and
  • revive indigenous resource management practices.

Although no new programs are slated to be created, the funds will pay for acquisition of “saildrones,” sailing vehicles that can gather oceanographic data autonomously. The solar- and wind-powered saildrones will be used to collect data to strengthen computer models for climate change forecasting.

Grabowski noted that the $50 million will not be used to explore efforts to specifically reverse climate change, instead focusing on data collection, mitigation and resilience.

HIMB Director Eleanor Sterling said that “this generous gift is a wonderful opportunity to support much needed interdisciplinary work that will help us to better understand ocean systems and indigenous management strategies and to develop effective approaches for ocean conservation.”

Interim SOEST Dean Chip Fletcher pointed to the increased public and governmental outreach efforts made possible by the grant.

“Through internships, mentoring, community engagement efforts and graduate research fellowships, we will grow our pool of scholars, policymakers and conservationists from underrepresented communities around our state,” Fletcher said.

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Without TCI-P, Vt. Will Explore Joining Western Climate Initiative

The Vermont Climate Council is considering the option of having the state join the Western Climate Initiative (WCI) as an alternative to its plan to reduce transportation sector emissions through the Transportation and Climate Initiative Program (TCI-P).

Joining WCI for transportation only could help fill an emission reduction gap in the council’s initial Climate Action Plan that was left when TCI-P destabilized in November. (See Vt. Climate Council Adjusts Course on TCI-P.)

The council released its plan in December without a clear alternative to TCI-P, instead including language that further studying other options is needed this year. Without the multistate cap-and-invest program, the plan has a 26% gap — equivalent to 0.9 million metric tons of carbon dioxide equivalent (MMTCO2e) — in emission reductions needed by 2030, according to a transportation task group of the council’s Cross-Sector Mitigation Subcommittee.

Under the 2020 Global Warming Solutions Act, transportation sector emissions must decline by 0.5 MMTCO2e by 2025 and an additional 1.38 MMTCO2e by 2030.

WCI is one of two options that the task group supports as needing further exploration because of their ability to reduce emissions equitably and cost-effectively, according to a memo the group shared with the council Monday. The WCI price per ton in November was $28.60, while the projected price per ton for TCI-P was $6.60 starting in 2023. Vermont already participates in the Regional Greenhouse Gas Initiative, which saw its highest auction price in December at $13/ton.

Under WCI, which California and Quebec participate in to cap and reduce emissions economy-wide, Vermont could tailor its program requirements for transportation to meet unique economic and environmental circumstances, the memo said.

As a complement to WCI, the task group recommended exploring a low-carbon fuel standard (LCFS) similar to programs already adopted in California, Oregon and Washington. Vermont has reduced emissions significantly in its electricity sector with a clean energy standard, and the council recommended in its initial plan that the state adopt a clean heat standard to reduce emissions in the buildings sector.

An LCFS, the memo said, could come at a higher cost than a cap-and-invest program. The latest program prices in California and Oregon were $147/ton and $126/ton, respectively. Vermont, however, could act independently to implement an LCFS without relying on the interstate collaboration necessary for other options, like TCI-P and WCI, to work, according to the memo.

Secondary to a cap-and-invest strategy in the council’s initial plan was a recommendation for Vermont to adopt California’s pending Advanced Clean Cars II (ACCII) regulation. ACCII, as proposed, would reduce emissions from new light- and medium-duty vehicles, while increasing zero-emission vehicles sales between 2026 and 2035.

The regulations could help Vermont achieve 11% of the 26% emission reductions needed in transportation by 2030, according to the memo, but the task group said that ACCII is not “sufficient on its own.” Additional policies and actions are needed to increase public investment in charging infrastructure and an expansion of electric vehicle purchase incentives.

The Agency of Natural Resources is already preparing to initiate a rulemaking for ACCII and California’s Advanced Clean Trucks regulation, as recommended in the council’s plan. However, a final rulemaking package for ACCII by the California Air Resources Board is not expected until June.

Members of the transportation task group will continue with an analysis of TCI-P alternatives and deliver a final recommendation to the council by May, and the council expects to adopt a final recommendation by June.

With the Vermont legislature scheduled to adjourn in May, any meaningful legislative action on a TCI-P alternative potentially could not happen until 2023. The council, however, expects the state can make short-term progress on transportation emissions with funding from the American Rescue Plan Act and the Infrastructure Investment and Jobs Act.

Gov. Phil Scott introduced his recommended fiscal year 2023 budget Jan. 18, with transportation funding of $40 million from ARPA. In addition, the state expects to receive $1.7 billion in IIJA funding over five years for transportation.

Those resources come with timing and funding matching requirements that limit how they can benefit long-term emission reductions, so they would not be available when the state needs to scale its efforts “massively” to meet 2030 requirements, the memo said.

The task group cautioned that, absent a framework for medium- and long-term emissions reductions combined with a dedicated funding mechanism, transportation sector investments from ARPA and IIJA will “fall off a cliff in 2027.”

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MMU Releases Fall Market Reports for SPP, WEIS

SPP’s Market Monitoring Unit is “strongly” recommending that transmission congestion rights’ (TCRs) funding shortfall be considered a high-priority item, according to its latest quarterly market report.

In the fall report, covering September through November, the MMU said the TCRs’ funding percentage varied over the trailing 12 months, ranging between 71 and 115%. It said the underfunding was down by more than $97 million when compared to fall 2020; TCR funding was it its lowest in October at 71%, driven by significant outages not included in the TCR model.

The Monitor said an item has been initiated in SPP’s roadmap process to correct the issue. Staff and stakeholders collaborate in this process to identify, educate, prioritize and approve new and existing initiatives for development over the next two to five years.

“Given the magnitude of the issue, we strongly recommend this item be considered as a high-priority item,” the MMU said in its report.

The report also found the average gas price at the Panhandle Eastern hub increased to $5.16/MMBtu in October, the highest price since March 2014 outside of last February 2021. The average gas price was up 143% from $1.99/MMBtu the previous fall.

Electricity prices also increased from 2020 to last fall, although at a lower rate. Day-ahead prices rose from an average of $18.21/MWh in 2020 to $33.72/MWh in 2021, an increase of 85%. Real-time prices increased from an average of $17.57/MWh to $31.27/MWh over the same period, up 78%.

The MMU said wind generation was the primary fuel type during the quarter, accounting for 38% of total generation, up 4 percentage points. Coal generation increased from 31% of production to 35%.

A webinar has been scheduled for Monday to allow stakeholders to discuss the quarterly report with MMU staff.

The Monitor has also released its latest quarterly report for the same period on SPP’s Western Energy Imbalance Service (WEIS) market.

It said the market’s average hourly load for September and November was about 2.3 GWh but was down slightly to 2.18 GWh in October. Coal remained the predominate fuel source, the report said, with 66% of total generation in September and decreasing to 62% by November. Hydroelectric generation was the second largest energy source, averaging 22% of total generation in September before trending downward to 17% by November.

The report found that average load and generation energy prices remained consistent with August pricing at slightly over $35/MWh until November, when there was an approximate decrease of 35%.

The market was averaging 1,692 MWh of hourly exports when September began, but they declined to about 1,500 MWh in October and November, the MMU said. Hourly imports averaged 626 MWh in September and increased throughout the quarter to 1,078 MWh by November.

The MMU said the WEIS market continues to struggle with ramp availability and short-term system flexibility, despite an abundance of online capacity. Many dispatchable resources are offered with minimal available dispatchable and/or ramp-able capacity, it said.

Economic limit parameter changes that force additional ramp needs, load forecast changes and changes in net schedule interchange also continue to drive market struggles to supply sufficient ramp. Market participants are also reluctant to offer additional resources because of risks associated with recovering costs when prices drop.

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MISO Hosts First In-person Meetings amid Pandemic

CARMEL, Ind. — MISO this week pulled off a series of in-person meetings at its three offices almost two years since the COVID-19 pandemic began.

The RTO held on-site committee meetings simultaneously in its offices in Carmel, Ind.; Eagan, Minn.; and Little Rock, Ark. Stakeholder attendance was sparser than usual with the Omicron variant peaking and company travel budgets bouncing back. Some speakers appeared through video conferencing.

“I will have to relearn to stand at a podium in front of stakeholders. It’s been nearly two years,” MISO’s Jeremiah Doner said in opening a Monday presentation on transmission cost allocation.

The grid operator required proof of full vaccination or a recent negative COVID test before admitting stakeholders into its conference rooms. Masking was optional, lunches were boxed and stakeholders had the option to sit more than six feet apart.

The grid operator gathered stakeholders in-person and off site late last year in Orlando, Fla., for its final quarterly board meeting of 2021. (See MISO Board of Directors Briefs: Dec. 9, 2021.)

MISO kicked off its first major meeting week of 2022 with a review of important subjects it plans to cover through the summer. It was the RTO’s inaugural executive update, which it plans to hold on a near-monthly basis to keep its stakeholder community abreast of its goals and work timeline.

Wayne Schug, vice president of strategy, said MISO will debut a rolling 12 to 18-month management plan that lays out committee tasks, time reserved for analysis and filing deadlines.

Leadership said the footprint’s rapid clean energy transition supports its case for long-term transmission planning and seasonal capacity auctions. It also said stakeholders should expect ongoing discussion in the first half of 2022 on its new participation models for energy storage and distributed resources; implementation of dynamic transmission line ratings; upgrades to its market-clearing engine; and an accreditation process for renewable, storage and hybrid resources.

Seventeen MISO utilities have emissions reduction targets greater than 80%, and five states in the footprint are considering 100% clean energy goals.

The topics will be explored under a lighter meeting schedule that calls for the RTO’s main stakeholder committees to hold eight meetings each per year. MISO plans to evaluate the meeting schedule’s effectiveness in May. (See MISO Modifies Stakeholder Meeting Schedule.)

Some stakeholders have objected to the slimmed-down schedule, arguing that MISO is facing industry changes that necessitate in-depth discussion and that stakeholders are supposed to dictate the frequency of meetings, not the RTO.

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PG&E Ends Probation as a ‘Menace to California,’ Judge Says

Pacific Gas and Electric (NYSE:PCG) ended five years of probation Tuesday night with the judge in charge lamenting that California’s largest utility had caused more damage on probation than it had before it was sentenced.

PG&E was placed on probation in January 2017 after being convicted of six felonies related to the San Bruno gas explosion, which killed eight people and destroyed a suburban San Francisco neighborhood in September 2010.

“While on probation, PG&E has set at least 31 wildfires, burned nearly 1.5 million acres, burned 23,956 structures and killed 113 Californians,” Judge William Alsup, of the U.S. District Court for Northern California, wrote in his parting comments on the case.

The utility pleaded guilty to 84 manslaughter charges in the 2018 Camp Fire, which leveled the town of Paradise, Alsup said. It faces five felony counts in the 2019 Kincade Fire in Sonoma County and four manslaughter charges from the 2020 Zogg Fire in Shasta County. The Dixie Fire, ignited by PG&E equipment last summer, was the second largest in state history at nearly 1 million acres and will likely result in lawsuits and possibly criminal charges, he said.

“So, in these five years, PG&E has gone on a crime spree and will emerge from probation as a continuing menace to California,” Alsup said.

“Rehabilitation of a criminal offender remains the paramount goal of probation,” he said. “During these five years of criminal probation, we have tried hard to rehabilitate PG&E. As the supervising district judge, however, I must acknowledge failure.”

Alsup told federal prosecutors on Jan. 3 that he would give “serious consideration” to a request for more probation time based on the state criminal charges against PG&E, but the U.S. Attorney’s Office decided not to seek an extension. (See Judge Refrains from Adding Time to PG&E Probation.)

PG&E Responds 

In a November court filing, PG&E assessed its own progress on probation, often in contrast to the judge’s remarks.

“PG&E acknowledges, deeply regrets and owns the tragic consequences of the wildfires caused by its equipment,” it said. “The company has taken a stand that catastrophic wildfires shall stop.” But during the past four years, thanks in part to the court’s supervision, its “electric grid is fundamentally safer.”

“PG&E believes it is on the right path,” it said. With its 70,000-square-mile service territory and the speed at which climate change appears to be impacting Northern California, there are “no fast or fail-proof options,” but the utility insisted it has changed.

PG&E is now “led by a board and senior management team that is new compared to those in place at the time of the San Bruno tragedy, the North Bay fires [in October 2017] and the Camp Fire,” it said. “Recognizing the need for the best thinking on operations, safety and risk, the company has hired leaders from stable, safe and operationally excellent utilities around the country,” including new CEO Patti Poppe, former head of CMS Energy in Michigan.

PG&E cited its use of public safety power shutoffs to prevent ignitions, which it did not use in 2017 but now employs widely in fire season along with fast-trip sensors to shut down power lines when faults occur.

The utility contended it has greatly improved its vegetation management. Trees and limbs falling on power lines have caused many of the major fires in the past five years.

“Between 2017 and 2021, PG&E increased spending on vegetation management from approximately $440 million a year to approximately $1.4 billion, representing an over 200% increase,” it said. “The total number of employees and contractors dedicated to vegetation management rose from 4,446 in 2019 to 10,265 in 2021.

“These unprecedented monetary and workforce investments have resulted in a significant amount of additional work,” it said. “In 2021, PG&E has removed or trimmed over 1.63 million trees as of Oct. 31 and forecasts it will remove or trim 1.82 million trees in total by year-end, a 20% increase over the 1.52 million trees worked in 2019.”

Alsup, however, said tree trimming remains one of the utility’s biggest problems.

“We remain trapped in a tragic era of PG&E wildfires because for decades it neglected its duties concerning hazard-tree removal and vegetation clearance, even though such duties were required by California’s Public Resource Code,” Alsup said. “In time, this neglect led to hazard trees and limbs falling on its distribution lines and sparking wildfires or becoming ‘ground faults,’ wherein the tree remains against a live wire and conducts sufficient electrical power to the earth to overheat and explode in flames.

“PG&E’s backlog of unattended trees and vegetation was staggering at the outset of probation,” he said. “As probation ends, PG&E remains at least seven years, [in] my estimate, from coming close to being current. During its criminal probation, all or virtually all of the wildfires started by PG&E distribution lines have involved hazard trees.”

The Camp and Kincade fires were started by broken transmission lines that ignited dry vegetation, he noted.

Alsup said he believes a “systemic cause” of distribution-line fires has been PG&E’s outsourcing of tree trimming and line inspections.

“A large part of the wildfire problem, as the [court-appointed] monitor has pointed out, has been sloppy inspection and clearance work, almost exclusively outsourced to independent contractors,” he said. PG&E should hire and train “as many arborists as are needed to fully comply with California’s Public Resource Code,” and the state should outlaw or restrict outsourcing.

The utility’s size is another problem, Alsup continued. PG&E operates 107,000 circuit miles of distribution lines and 18,500 miles of transmission lines, with about half its territory in high fire-threat districts.

Alsup said he has “come to fear” that PG&E should be split into at least two entities, one to serve fire-prone areas and one or more to serve the rest of its 5.5 million electric customers.

“Less sprawling utilities would be easier to train and to instill practices and procedures that truly put safety first.”

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Dueling Bills Have Different Takes on Wash. Siting Council

Two Washington bills seek opposite outcomes for the state’s Energy Facility Site Evaluation Council (EFSEC).

The council, comprising representatives from several state agencies, makes recommendations to the governor for final decisions on the placement of solar farms, wind turbines and other energy resources.

If a wind or solar developer opts to seek state approval instead of obtaining county permits, it can bypass county governments by going through EFSEC. Or a developer can choose to have the appropriate county government handle the permitting, sidestepping EFSEC. 

Rep. Mark Klicker (R) has introduced one bill (HB 1871) to stop EFSEC from reviewing solar and wind projects until late 2023 after a task force studies the issue.

Klicker represents much of Benton County, where heavy opposition has surfaced to the Horse Heaven Hills wind turbine proposal — mostly because many residents of Washington’s Tri-Cities area don’t want to see windmills on their southern horizon. (See Wind Project Sows Controversy in Horse Heaven.) That bill showed up at a Tuesday public hearing before the House Environment and Energy Committee. 

Also on Tuesday, the same committee heard testimony that mostly supported a bill (HB 1812) by Rep. Joe Fitzgibbon (D) that would bolster the authority of EFSEC while also boosting tribal participation in reviews when needed. Fitzgibbon is the committee’s chairman, meaning his bill has the better chance of moving beyond the committee.

On Knicker’s bill, Tuesday’s testimony stressed that Eastern Washington residents believe that wind and solar farms chip away at their tax bases and that their region is being unfairly targeted to provide most of the state’s alternative energy sources. Critics of EFSEC argue the council is not receptive to local concerns. Habitat concerns did not pop up in the hearing.

“You guys are in too big of a hurry to meet climate change goals,” said Klickitat County Commissioner Dan Christopher. Josh Weiss, a lobbyist for Benton County said, “Local planning is capable of dealing with these projects.” 

“It does things to the people of rural Washington instead of doing things for them,” said Dave Barta, representing the Farm Bureau for Klickitat and Yakima counties. 

However, EFSEC Chair Kathleen Drew said the council has approved only three wind and solar projects so far with only a handful still under review. “The vast majority of wind and solar [projects] have gone before the county governments. I believe [EFSEC’s] siting process is the most thorough environmental review.”

Testimony on Fitzgibbon’s bill was overwhelmingly in favor of the legislation. There was very little overlap between the people testifying on the two bills. The bulk of the support came from labor and environmental organizations.

“We’re for any effort to bring speed and certainty to the process,” Matt Steuerwalt of NextEra Energy Resources said. Kelly Hall of Climate Solutions said, “We need to consolidate bringing new jobs to the state.”

The bill would take EFSEC out of the umbrella of the Washington Utilities and Transportation Commission and provide it with its own separate budget. It would also add pipelines to its jurisdiction, streamline some procedures and bolster tribal participation in matters affecting the Native American tribes.

The hearing also produced the only mention of concerns about solar and wind projects encroaching on sensitive wildlife habitat. The Washington Department of Fish and Wildlife said routing the process through EFSEC would provide stronger protections for habitat.

The Tulalip, Yakama and Puyallup nations warned against streamlining the review process too much, not wanting the state to rubber-stamp proposals.

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San Francisco Wins Against FERC, PG&E in DC Circuit

The D.C. Circuit Court of Appeals overturned FERC on Tuesday in two cases brought by the city and county of San Francisco against Pacific Gas and Electric (NYSE:PCG) for failing to deliver electricity to customers in violation of its wholesale distribution tariff (20-1084).

In one case, the city contested PG&E’s refusal to provide lower-voltage secondary service to many sites within the city. San Francisco filed a complaint with FERC in January 2019 alleging PG&E had consistently refused to make new interconnections at secondary voltage unless the total electricity demand was less than 75 kW.

PG&E instead offered to connect higher-voltage primary service, which requires the installation of transformers and carries higher fixed costs for ratepayers, San Francisco said. The city argued that the practice violated PG&E’s tariff because it requires the utility to offer secondary service when requested and to expand its infrastructure where necessary.

The company argued that it did not categorically deny secondary service in cases where demand exceeded 75 kW and said its denials in some cases were based on technical, safety and reliability concerns.

FERC denied San Francisco’s complaint, ruling that PG&E should decide what level of service is appropriate for customers.

“While the [wholesale distribution tariff] does not preclude a … customer from requesting the level of service that it wishes to take, PG&E, as the wholesale distribution service provider, is ultimately responsible for the safety and reliability of its distribution system,” FERC wrote in its April 2020 order (EL19-38). “Accordingly, we find that it is appropriate for PG&E, as that provider, to have discretion to determine what level of service is both appropriate and available based upon the status and configuration of its existing wholesale distribution system facilities and the nature and location of the interconnection request.”

The initial decision, as well as its order on rehearing that upheld it later in September, were unanimous among the commissioners at the time, which included current Chair Richard Glick (D) and Commissioner James Danly (R).

But in an opinion written by D.C. Circuit Judge Judith Rogers, a three-judge panel found that FERC failed to scrutinize the safety and reliability risks cited by PG&E. The judges also rejected PG&E’s contention that it decides appropriate voltages case by case.

“Evidence before the commission showed that since 2015, many of San Francisco’s new interconnection requests exceeding 75 kW have been denied secondary service by PG&E, and that the proportion of new interconnections above 75 kW receiving primary service has increased since 2015,” the court said. It cited a July 2019 letter written by PG&E to San Francisco saying it was no longer “willing to make additional accommodations” for secondary service.

“The July 1, 2019, letter hardly indicates that PG&E intends to evaluate San Francisco’s applications on a case-by-case basis,” the court wrote.

On rehearing FERC had said the “75-kW threshold is merely a ‘guidepost,’ while reaffirming its position that PG&E makes case-by-case determinations of which voltage to provide,” the court noted.

“Even if the 75-kW threshold is a guidepost, however, that kind of numerical threshold is the type of requirement that the ‘rule of reason’ requires be stated in the tariff,” the court said.

“Because the commission did not adequately explain any operational or engineering rationale justifying PG&E’s 75-kW ‘guidepost’ and did not explain why that guidepost did not need to be in the filed tariff, the court vacates the voltage orders and remands the case to the commission for further proceedings consistent with this opinion,” it said.

Grandfathering Service

In the second case, which was consolidated with the first, San Francisco argued that PG&E had denied service to delivery points that were eligible for it under a tariff grandfathering provision.

In interpreting the provision, PG&E cited the tariff’s reference to Federal Power Act Section 212(h), which prohibits mandatory retail wheeling with certain exceptions.

“No order issued under this chapter shall be conditioned upon or require the transmission of electric energy directly to an ultimate consumer … unless such entity was providing electric service to such ultimate consumer on Oct. 24, 1992,” the FPA says.

PG&E said that meant it had to serve end users it served in 1992 but not those that had moved. San Francisco argued the tariff requires PG&E to serve even those customers that had relocated since 1992.

A FERC administrative law judge interpreted the FPA, given prior FERC orders, as supporting San Francisco’s argument “that grandfathering applies to the class of customers that was eligible to receive wholesale distribution service on Oct. 24, 1992, regardless of where in the city those customers may be located now or in the future.”

FERC reversed the ALJ’s decision, agreeing with PG&E’s interpretation of the tariff’s grandfathering provision.

The court, however, said FERC’s interpretation of the tariff was too narrow and its “attempts to defend its interpretation [were] unpersuasive.”

“That the tariff references ‘points of delivery’ does not necessarily imply that only specific points of delivery may be grandfathered, and those references to ‘points of delivery’ do not change the fact that the tariff expressly references the criteria of Section 212(h)(2),” it said.

The court criticized FERC’s orders in the case as demonstrating a “troubling pattern of inattentiveness to potential anticompetitive effects of PG&E’s administration of its open-access tariff.” Faced with claims that PG&E was refusing service to San Francisco customers, FERC “fell short of meeting its duty to ensure that rules or practices affecting wholesale rates are just and reasonable,” it said.

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DOE Initiatives to Rev up $1B in Community Solar Savings

Energy Secretary Jennifer Granholm was at the National Community Solar Partnership’s Annual Summit on Tuesday to announce the Department of Energy’s latest initiatives aimed at deploying enough community solar in the next three years to provide $1 billion in savings for 5 million U.S. households.

According to the DOE, the U.S. currently has about 5.2 GW of community solar online across the country, but hitting the NCSP’s ambitious target will require getting to 20 GW by 2025.

The three initiatives announced Tuesday are intended to overcome key barriers to deployment: expanding state-level programs, improving access to finance and providing technical assistance to community organizations and other stakeholders to accelerate development of these projects.

“Not everybody can put solar panels on the roof,” Granholm said at the virtual summit. “And too many of those folks are in lower-income communities and communities of color. They don’t have to be left out, and we’re going to make sure that they won’t be. With community solar, we can give them access to clean and cheap solar energy, all at the same time.”

The DOE also wants to double household savings from community solar from the current average of 10% to 20%, which is about the same level of savings as residential solar owners get from their panels, said Kelly Speakes-Backman, principal deputy assistant secretary for energy efficiency and renewable energy.

The three initiatives announced at the summit include:

  • A States Collaborative, which will support the development and expansion of state-level community solar programs. State energy officials and program administrators from about half the states and the District of Columbia will be part of the group.
  • The Credit Ready Solar Initiative, which will enlist lenders, philanthropic organizations and community solar developers to improve projects’ access to financing, especially for projects serving low-to-moderate income communities.
  • The NCSP Technical Assistance program, which will provide $2 million in rolling grants to program partners to “help them accelerate implementation, improve the performance of their program or project, and build capacity for future community solar development,” according to a DOE press release.

A Concentrated Market

Community solar allows individuals or groups who cannot put solar on their roofs — such as commercial or residential renters — to subscribe to a project, often located in or near their community, and get a credit on their utility bills for a portion of the electricity produced. According to the DOE, 22 states and the District of Columbia have policies that allow community solar, but four states — Minnesota, Florida, Massachusetts and New York — account for nearly three-quarters of the existing market.

That concentration is why the DOE’s States Collaborative is so important, Illinois Gov. JB Pritzker (D) said at the summit.

“When states can access each other — share best ideas, work together — it will reduce barriers to expanding community solar,” Pritzker said. “Knowledge sharing is critical for us. … The more we can learn from each other across the states, the more quickly we can grow more effective programs.”

Projects being developed under Illinois’ Solar for All community solar program are specifically targeted at low-income households, nonprofits and public facilities, he said.

Victor Rojas, senior vice president at Sustainable Capital Advisors, said the Credit Ready initiative will address a long-standing gap in private investment in community solar.

Community solar developers need to ask not only whether projects are shovel-ready,” but are the projects … actually accessible to capital and developed and framed in such a way that capital finds attractive,” Rojas said. “We just haven’t done a good job doing that to date.”

In yet another announcement, Granholm said the Coalition for Community Solar Access (CCSA) has committed to meeting the DOE’s goal of 20 GW of projects online by 2025.

In the DOE press release, CCSA CEO Jeffrey Cramer said 80 community solar providers will be working with the organization to accelerate project deployments. “With the combination of the DOE’s … initiatives and the adoption of other critical actions by state and federal policymakers, industry can meet this goal and satisfy pent-up demand,” he said.

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FERC Directs More Clarity in Order 864 Filings

FERC last week approved NorthWestern Corp.’s (NASDAQ:NWE) compliance filing under a commission order that ensures transmission formula rates properly address excess and deficient accumulated deferred income taxes (ADIT) resulting from current and future tax-rate changes (ER20-1090).

The ruling was one of three FERC issued on Thursday related to Order 864. The 2019 directive required public transmission providers with formula rates under a tariff or rate schedule to make revisions accounting for changes caused by the Tax Cuts and Jobs Act of 2017. The order also directed entities to include a mechanism in their rates that deducts any excess ADIT or add any deficient ADIT to their rate base.

The commission found that NorthWestern partially complied with Order 864’s requirements and directed the company to make a further compliance filing within 60 days.

NorthWestern proposed incorporating two new worksheets addressing Order 864’s requirement for a rate base adjustment mechanism, a summary worksheet and a worksheet specific to each tax change. It also said it would add another worksheet calculating the excess and deficient ADIT.

FERC said NorthWestern’s adjustment mechanism did not fully apply to any future tax rate changes giving rise to excess or deficient ADIT and ordered it to include “deficient ADIT” in the summary worksheet. The commission also directed NorthWestern to include “deficient ADIT” in its tax allowance adjustment mechanism.

That latter mechanism allows a transmission company to decrease or increase its income tax component by any amortized excess or deficient ADIT, respectively. FERC found NorthWestern’s formula description did not accurately reflect the formula in a separate worksheet and ordered it to make revisions.

The commission also ordered the company to include “deficient ADIT” in the notes of its summary worksheets.

PacifiCorp Partially Rejected

FERC also rejected parts of an Order 864 compliance filing by PacifiCorp (NYSE:BRK.A) because of worksheet shortcomings and directed the utility to submit an additional compliance filing in 60 days (ER20-1828).

The commission found PacifiCorp’s ADIT filing did not comply with Order 864’s categories 1 and 2 worksheet requirements.

In category 1, “Order No. 864 required public utilities to include in their permanent ADIT worksheets ‘how any ADIT accounts were remeasured and the excess or deficient ADIT contained therein,’” FERC said.

PacifiCorp’s proposed ADIT worksheets did not demonstrate how any ADIT accounts were remeasured but only showed the “excess and deficient ADIT contained therein, and then allocated the ADIT amounts to transmission without providing additional illustration or explanation of their calculations,” FERC said.

To satisfy the category 1 requirements, PacifiCorp “must provide the pre-tax rate change and post-tax rate change ADIT account balances, in addition to the resulting excess and deficient ADIT already provided,” the commission said. “Further, such information must be provided at a level of detail such that interested parties can identify the source (i.e., the originating accounts) of excess or deficient ADIT in the proposed ADIT worksheet and verify excess and deficient ADIT resulting from the Tax Cuts and Jobs Act and future tax rate changes.”

In category 2, PacifiCorp identified end-of-year balances of excess and deficient ADIT but did not provide the full accounting for any unamortized excess or deficient amounts, FERC said.

“Specifically, the ADIT worksheets do not display the gross-up on unamortized excess and deficient ADIT included in these accounts,” it said. “As such, in the compliance filing ordered below, we direct PacifiCorp to display the gross-up on excess and deficient ADIT included” in two specified accounts.

Duke Partially Approved

Finally, the commission partially accepted Duke Energy Ohio/Kentucky’s (DEOK) (NYSE:DUK) proposed revisions to its transmission formula rate, directing a further compliance filing within 60 days (ER20-1832).

DEOK argued its existing formula rate included a rate base adjustment mechanism for several of its accounts “as adjusted by any amounts in contra accounts identified as regulatory assets or liabilities.” But DEOK proposed adding language to an existing account “to maintain rate-base neutrality in the event of a change to income tax rates” and that the account balance would be derived form the new ADIT worksheet it proposed to comply with Order 864.

The compliance filing proposed adding language to the formula rate “to incorporate the amortization of excess and deficient ADIT into the income tax calculation, in order to return or recover excess/deficient ADIT.” DEOK also proposed incorporating a new permanent ADIT worksheet into its formula rate that would annually track information related to its “protected and unprotected deficient deferred income tax” and to provide an “informational reconciliation of accounts remeasured as a result of federal and state income tax rate changes.”

American Municipal Power (AMP) made several protests of the filing, alleging that DEOK may be retaining a portion of excess ADIT because of the Kentucky corporate income tax rate changing from 6% to 5% in 2018. AMP said DEOK “improperly amortized certain excess ADIT related to that change,” requesting that the commission require DEOK to refund the amounts with interest and recalculate its 2019 annual update “because DEOK has not ensured rate-base neutrality.”

The commission found that the utility’s rate-base adjustment mechanism partially complied with Order 864, saying the mechanism “allows DEOK to deduct any excess ADIT calculated in the proposed ADIT worksheet from rate base, thus preserving rate-base neutrality for that component” and that it may be applied to “any future federal tax rate changes that give rise to excess or deficient ADIT.”

But it also said it agreed with AMP that the mechanism does not reflect the 2018 Kentucky excess ADIT as a “contra” in several accounts “instead of using its proposed rate-base adjustment mechanism.”

The commission said DEOK’s proposal “does not show how much of the 2018 Kentucky excess ADIT ultimately were included in other components” of the rate and how it meets the requirements of the ADIT worksheet.

It directed DEOK to show how its proposal for the state tax rate changes are consistent with the requirements of Order 864, including “how transmission customers will receive the full amount of both protected and unprotected excess ADIT balance to be returned to transmission.”

FERC also found that DEOK’s ADIT worksheet partially complied with Order 864, directing more changes. While the worksheet shows adjustments from the originating ADIT accounts to the regulatory asset and liability accounts, it does not include the beginning balance of the remeasured ADIT amounts, the commission said.