Search
`
November 6, 2024

Posted on

MISO Steering Committee Blocks Adds to Stakeholder Guidelines

MISO stakeholder committee chairs last week elected not to adopt rules regulating stakeholder presentations during meetings.

On Wednesday, the Steering Committee, comprising chairs from eight MISO committees reporting to the grid operator’s Advisory Committee, declined to advance a suggested insert drafted by Clean Grid Alliance’s Rhonda Peters to its Stakeholder Governance Guide.

The addition would have dictated that stakeholders presenting during meetings must be “treated uniformly and without discrimination or preference.” It also would have compelled the RTO to deliver its own presentations and discuss suggested changes by stakeholders before it could adopt them.

“Stakeholders cannot adequately and sufficiently represent MISO’s interests or accountability,” the language said.

Peters said the grid operator’s adoption of stakeholder suggestions without fully vetting them with the larger stakeholder community has been an issue that has come up several times over the 14 years she’s been participating in the stakeholder process. She said staff will sometimes file with FERC tariff modifications on stakeholders’ recommended changes without addressing the edits with stakeholders.

Peters said the most recent example arose after a Planning Advisory Committee meeting when MISO filed tariff changes pertaining to transmission owners’ reinstated option to self-fund network upgrades. She said staff should have vetted the edits pertaining to the self-funding option with the Interconnection Process Working Group before drafting and filing the changes.

MISO in 2018 acted on FERC’s direction and reinstated TOs’ right to self-fund network upgrades necessary for new generation. The decision has been a hot-button issue, spawning three years’ worth of reopened contracts, refunds to interconnection customers and condemnation from one FERC commissioner. (See FERC Upholds MISO Self-fund Order, Glick Dissents.)

“There are some stakeholders that MISO feels represent them,” Peters said. “All stakeholders should be treated in the same manner, and that has not been happening.”

She implied that TO recommendations carry more weight with the RTO than those from other stakeholders.

Committee chairs said while they were sympathetic to the issue, they didn’t see a need to add a section on stakeholder presentations to the governance guide.

“I’m worried if we try to add language to address every situation in the Stakeholder Governance Guide, it will become unwieldy and collapse under its own weight,” WEC Energy Group’s Chris Plante, the Resource Adequacy Subcommittee chair, said.

Plante said he’d rather see committee chairs handle these types of situations. Planning Advisory Committee Chair Cynthia Crane, with ITC Holdings, agreed that the new section would be “overly prescriptive.”

Ameren’s Ray McCausland, who chairs the Reliability Subcommittee, asked stakeholders to bring specific violations of stakeholder treatment to the Steering Committee instead of prescribing vague language in the governance guide.

Market Subcommittee Chair Megan Wisersky, with Madison Gas and Electric, said that the guide’s addition could discourage some stakeholders from coming forward with presentations. In MISO’s stakeholder process, any stakeholder is free to present in meetings if it gives the grid operator enough notice.

Clean Grid Alliance’s Natalie McIntire asked how the issue could effectively be addressed by the committee chairs and vice chairs. “I just feel like there needs to be another solution, one that does function,” she said.

Peters said if she couldn’t get the language accepted, the next step might be taking the issue to MISO’s alternative dispute resolution process.

Customized Energy Solutions’ David Sapper said he’d be interested in hearing MISO’s process for accepting stakeholder suggestions and making FERC filings based on them.

The Steering Committee has no current plans to further address the issue.

Posted on

Massachusetts Solar Watchers See Warning Signs in Local Siting

As solar developers eye Massachusetts and its growing incentive program, new challenges are arising that could continue to put up barriers to development in the state.

In December, Massachusetts doubled its solar incentive program, the Solar Massachusetts Renewable Target, from 1,600 MW to 3,200 MW of capacity, a boon to the growth of the solar industry there.

But an unexpected level of resistance and confusion at the local level continues to hinder solar developers.

Jonathan Persaud 2022-02-25 (RTO Insider LLC) FI.jpgJonathan Persaud, Grasshopper Energy | © RTO Insider LLC

“I think we’ve certainly bruised our knees a tremendous amount on the coordination that needs to go on between the regulator, utility and even local townships themselves,” said Jonathan Persaud, chief commercial officer of the Canadian solar company Grasshopper Energy.

Ensuring that local townships understand the projects’ objectives has “proven to be a much, much more heavy lift than certainly we ever imagined coming into Massachusetts,” he said during RE+ Northeast on Thursday.

Speaking at the conference, Persaud and other industry and government representatives described a difficult landscape when it comes to dealing with local governments.

Municipalities, they said, are uneasy about the financial and safety prospects of having solar projects come to town and feel harried by developers.

The Tax Question

Tim Roughan 2022-02-25 (RTO Insider LLC) FI.jpgTim Roughan, National Grid | © RTO Insider LLC

“Siting reform is critical,” said Tim Roughan, director of regulatory strategy for National Grid. At the base level, he added, the simplest way to incent cities and towns to want solar development is to “bribe them.”

He suggested that developers and policymakers should look for ways to incentivize solar projects to give more back to communities.

“You need a way so that folks will have certainty; the town will have certainty about how they’re going to pay their bills,” Roughan said.

Massachusetts law exempts many solar systems from property taxes, and some solar farms skirt taxes by using their output to heat or cool buildings and take advantage of an old state solar water heating incentive, Roughan added.

“That town doesn’t want any more solar,” he said. “Can you blame them?”

Paying more in taxes is not necessarily a dealbreaker for developers.

“I don’t think many solar companies would say that we’re unwilling to pay property taxes,” said Jessica Robertson, director of New England policy and business development for Borrego. “I think we’re absolutely willing to pay and contribute to the local economy.”

By removing the risk, she added, paying property taxes can be borne by the project economics.

Frustration and Education

Elizabeth Mahony 2022-02-25 (RTO Insider LLC) FI.jpgElizabeth Mahony, assistant attorney general and senior energy policy adviser to Massachusetts Attorney General Maura Healey | © RTO Insider LLC

Creating a good relationship with communities involves more than money, said Elizabeth Mahony, an assistant attorney general and senior energy policy adviser to Massachusetts Attorney General Maura Healey.

“There are big questions out there because it’s not just necessarily a cost issue; it’s a ‘they’re tired’ issue,” Mahony said “A lot of [developers] have hit up the same towns quite a number of times.”

The towns are frustrated and “worried about their future agricultural needs,” she said.

Also serving as a hindrance to further development is a continuing lack of information and education about solar.

In some instances, Persaud said, he has had to explain that solar modules don’t give off radiation and that lithium-ion batteries are not nuclear bombs.

“We need to provide incentives and also education,” he said, “And we need to provide assistance from an urban planning point of view.”

Posted on

FBI: Conspirators Planned Grid Attack to Start Race War

Three men who pleaded guilty Wednesday to conspiring to damage U.S. electric substations hoped to “sow hate [and] create chaos” inspired by “racially or ethnically motivated violent extremist view,” the Justice Department said.

According to a press release, Christopher Cook of Ohio, Jonathan Frost of Indiana and Texas, and Jackson Sawall of Wisconsin each admitted to one count of conspiring to provide material support to terrorists for the purpose of destroying energy facilities. The charges carry a maximum prison term of 15 years.

Prosecutors further recommended a 30-year term of supervised release after the men are released to include the installation of monitoring software on all their computing devices, a ban on the use of encrypted communication platforms and mandatory counseling for violent extremism and mental health. Defendants would also need to clear any new email or social media accounts with probation officers.

As alleged by prosecutors and confirmed by defendants in their plea agreements, the plot began in October 2019 when Frost, age 24, and Cook, 20, met in a chat room.

Because Cook “appeared … to be serious about engaging in action,” Frost suggested they attack power substations across the country with high-powered rifles. By damaging the transformers in the substations, the plotters hoped not only to distract the government and sap its resources in repairing the transformers; they also wanted to spark “confusion and unrest” in the affected regions and possibly even start a civil war.

The conspirators’ plans were reminiscent of the attack on Pacific Gas & Electric’s Metcalf substation in California in 2013, when several gunmen opened fire on the facility, severely damaging 17 transformers. (See Substation Saboteurs ‘No Amateurs’.) The prosecution did not say whether Cook and Frost were specifically inspired by the incident, but the Metcalf attack was mentioned in Large Power Transformers and the U.S. Electric Grid, a publication of the Department of Energy discussing the impact of transformer outages that Frost shared with his fellow planners.

Recruitment Continued Online

As they continued to build their plans, Cook and Frost began to divide the labor, with Cook focusing on recruiting more operatives (seeking younger targets who were “less likely [to be] members of law enforcement”) and Frost taking over the logistical side of the operation.

Cook’s appeals revolved around white supremacist and neo-Nazi ideology, drawing on writers such as James Mason and Alexander Slavros, founder of the far-right message board Iron March. Among the pair’s more ambitious goals for the project was to disable power across the entire country for an extended time, leading to an economic depression that would cause Americans to lose faith in political leaders and inspire new white leaders to rise up and overthrow the system.

Sawall, 22, joined the group in 2019. Already a friend of Cook, he helped with the recruitment effort and also ran the group’s web presence “The Front,” through which he and Cook screened potential new operatives. Those who showed promise were invited to join a more exclusive group called “Lights Out,” dedicated to the planned attack. Specific details of the plan were restricted to yet another forum called “Lights On,” which included only a few people besides Sawall, Cook and Frost. Those other participants have not been identified.

At one point each participant was to recruit and manage a cell of attackers for his region; however, this approach proved “unrealistic,” and the members decided to handle the destruction themselves. Further refinements to the plan included building explosive devices to distract law enforcement during the attack and making necklaces containing suicide pills to be worn by each participant in case of capture.

In-person Meetings Begin

Frost gave the necklaces to Cook and Sawall during a meeting in Ohio, the first time all three met in person. As part of the meeting Sawall and Cook spraypainted neo-Nazi graffiti on a bridge. They had planned to continue painting graffiti, as well as hanging posters and cutting down a telephone pole to raise awareness of The Front, but “these plans were derailed after a traffic stop, during which Sawall swallowed his suicide pill.”

Sawall survived his suicide attempt, while Frost and Cook continued to travel without him. Frost sold Cook a homemade rifle and taught him how to shoot it. The two went to Texas in March 2020 when Frost was on spring break, with Cook planning to recruit contacts he had made in the state. However, one of the contacts lost their phone and couldn’t meet with the pair.

The person who found the phone saw the messages and white supremacist material on it and told the two they were notifying law enforcement. Cook and Frost had several more run-ins with police over their travels, which led them to split up. Cook visited more potential recruits over the next few months in various cities.

Prosecutors did not disclose the circumstances of the group’s arrest, but according to the Milwaukee Journal Sentinel, the FBI’s counterterrorism task force picked up the case after a Canadian man detained for crossing the border with several guns in 2019 told agents he was visiting Cook. Investigators visited Cook, who discussed his political views with the agents. Undercover agents later joined the group’s message boards and surveilled the three men when they met in 2020.

“Those inspired to commit terrorist acts in the name of hate pose a serious threat to our nation,” said J. William Rivers, head of the FBI’s Cincinnati Field Office. “I am thankful for the Joint Terrorism Task Force and our law enforcement partners who work each day to prevent this type of violence from occurring in our communities.”

Posted on

Avangrid CEO: Benefits of OSW Restructuring Not Reflected in Stock

The full benefits of Avangrid’s recent Vineyard Wind joint venture deal with Copenhagen Infrastructure Partners are not yet “fully appreciated” by the stock market, CEO Dennis Arriola said Wednesday.

With the completion of a JV restructuring in January, Avangrid Renewables, the U.S. offshore wind arm of Avangrid (NYSE:AGR), now solely owns a 4.5 GW project portfolio along the East Coast, Arriola said during an earnings call Wednesday.

“This control allows us to more easily deliver incremental value and future growth and to fully capture the value of our offshore wind investment,” he said, adding that the value is not “reflected” in Avangrid’s stock price.

On Thursday, the company’s shares opened at $42.50 and had a 52-week range of $42.24-$55.57, according to Yahoo Finance.

Avangrid and CIP agreed last fall to split up the assets of their Vineyard Wind JV. They closed the transaction in January, allowing Avangrid to buy the lease area (OCA-A 0534) that has the proposed 804-MW Park City Wind project and the 1.2-GW Commonwealth Wind project. In turn, CIP took full control of a nearby lease area (OCS-A 0522), and the companies are continuing to co-develop the 800-MW Vineyard Wind 1 project.

Avangrid’s total OSW portfolio is 4.9 GW, which includes Park City, Commonwealth, half of Vineyard Wind 1, and the estimated 2.5-GW Kitty Hawk lease off the cost of North Carolina.

“By being an early mover in offshore, we have lease areas which are undervalued based on current market prices,” Arriola said.

Avangrid paid $168 million for the lease area where Park City and Commonwealth are sited. Together with the location of Vineyard Wind 1, the lease areas are “currently valued in the hundreds of millions of dollars,” he said.

That estimate, he added, is “before we continue to develop the portfolio and further increase its value.”

Avangrid’s transaction with CIP will allow the company to generate a gain of $175 million for the first quarter of this year, Arriola said. By securing direct ownership of its portfolio, the company can control project financing structures, including new partnerships that will generate further gains beyond what it will report for the current quarter.

“There are various potential partners that don’t want [power purchase agreement] or permitting risk, but they’re able to pay a higher valuation premium for a piece of a project once those development steps have been completed,” Arriola said.

Avangrid Renewables is an approved bidder in the Bureau of Ocean Energy Management’s (BOEM) New York Bight OSW lease area auction that started Wednesday. The bids for six lease areas ranged between $140 million for 43,000 acres and $900 million for 126,000 acres when BOEM took a recess in bidding at the end of Thursday. By comparison, the company Offshore MW paid $150,197 in 2015 to secure the 167,000-acre original lease area covering Vineyard Wind 1, Park City and Commonwealth.

Earnings

Avangrid, which is a subsidiary of Spain-based Iberdrola, reported 2021 earnings of $707 million ($1.97/share), up $126 million ($0.09/share) from 2020. For the fourth quarter, the company reported earnings of $164 million ($0.42/share), down $2 million ($0.12/share) from the same period in 2020.

For the renewables unit, Avangrid reported a loss of $14 million ($0.04/share) in 2021, compared with a $4 million ($0.01/share) loss in 2020. The company reported renewables unit earnings of $131 million ($0.37/share) for the fourth quarter, up $28 million ($0.04/share) from a year earlier.

Posted on

Mountain States Partner to Secure Hydrogen Hub

Four Western states — Colorado, Wyoming, Utah and New Mexico — are teaming up to compete for a share of $8 billion in federal funds that will be awarded for the development of regional clean hydrogen hubs.

Under an agreement announced Thursday, the four states will work together to develop a Western Inter-States Hydrogen Hub that will include facilities in each state.

The states will jointly submit a hydrogen hub proposal when the Department of Energy opens the application period, which is expected in May. The states will also respond to DOE’s request for information issued this month.

Each state will appoint up to three members of a workgroup to coordinate the efforts.

“These states are uniquely situated to become a clean hydrogen hub given the presence of high-quality wind, solar, biomass, natural gas and other energy resources,” a release from New Mexico Gov. Michelle Lujan Grisham’s office said.

The agreement signatories include two Democrats — Lujan Grisham and Colorado Gov. Jared Polis — and two Republicans, Utah Gov. Spencer Cox and Wyoming Gov. Mark Gordon.

As part of the agreement, each state promised to not participate in any other hydrogen hub proposal. But the agreement encourages the individual states “to enter into separate agreements with other entities that further hydrogen development in their states.”

If all four states agree, other states may join the partnership.

Competition Developing

The federal Infrastructure Investment and Jobs Act, which President Joe Biden signed in November, allocates $8 billion in funding for four or more regional hydrogen hubs. The infrastructure law also includes $1 billion for a clean hydrogen electrolysis program to reduce costs of hydrogen produced from clean electricity and $500 million for clean hydrogen manufacturing and recycling initiatives.

Competition for the money could be heating up.

In addition to Thursday’s announcement from the four Western states, a bill moving through the Washington legislature would authorize the use of state funding to boost that state’s bid for federal hydrogen hub money. (See Fast-moving Bill Seeks to Win Hydrogen Hub for Wash.)

Proponents say Washington’s abundant water supply and extensive hydroelectric network make it a good hydrogen hub candidate.

The agreement among the four Mountain states argues that the region is ideally suited to serve as a hydrogen hub. Reasons include the area’s sophisticated oil and natural gas industry, a robust energy transportation infrastructure, established carbon management infrastructure and favorable geology.

In a statement, Colorado Gov. Polis pointed to “intellectual capital” in his state, which includes universities and the National Renewable Energy Laboratory.

Utah is home to the Intermountain Power Plant, a coal-fired facility that the Los Angeles Department of Water and Power plans to convert to a combined cycle natural gas-fired facility. The plant will initially be able to burn a fuel mixture containing 30% hydrogen, eventually operating on 100% hydrogen, according to the Green Hydrogen Coalition.

How IPP might fit into the four states’ plans for a hydrogen hub remains to be seen. The plant provides power to Los Angeles, which is viewed as a center of green hydrogen development.

Arizona Activity

Another possible contender is Arizona. In October, DOE announced $20 million for a demonstration project that will produce green hydrogen using power from the Palo Verde nuclear plant about 55 miles west of Phoenix. (See Palo Verde Hydrogen Demo Gets $20M from DOE.)

“Arizona is on the cusp of becoming the epicenter of clean hydrogen production,” Arizona Corporation Commission member Lea Marquez Peterson said in a statement at the time.

Marquez Peterson said that the ACC had approved a special rate agreement between Arizona Public Service Co. and fuel cell and battery-electric truck manufacturer Nikola Corp., which is based in Arizona.

In its 2021 annual report, filed on Thursday, Nikola noted that hydrogen coalitions and stakeholder groups are increasing their involvement in state and national initiatives, including support for the hydrogen agenda in the Infrastructure Investment and Jobs Act.

In addition, “new stakeholder groups and initiatives [are] forming in preparation for national investment from the U.S. Department of Energy in Regional Clean Hydrogen Hubs across the country,” the company said.

Posted on

PSEG Looks to Post-fossil Future

Fresh from closing the sale of its fossil generating plants, Public Service Enterprise Group (NYSE:PEG) executives told investors during the utility’s fourth-quarter earnings call Thursday that they are looking at further investment in offshore wind projects and seeking a longer-term subsidy flow for their South Jersey nuclear plants.

The company on Wednesday completed the sale of its fossil plants in New York and Connecticut to a fund controlled by ArcLight Capital Partners, according to a company release, the last of its 6,750-MW portfolio of 13 fossil generating units, according to the company’s earnings presentation.

PSEG CEO Ralph Izzo said the sale will free up the utility to pursue a “robust set of regulated and contracted opportunities” that will enhance its “already compelling environmental, social and governance profile.” The company is looking at clean energy and infrastructure investments “to drive regulated utility growth, with the vision toward powering a future where people use less energy, and it’s cleaner, safer and delivered more reliably than ever,” he said.

The sale of the fossil units capped a year of “significant accomplishments,” Izzo said. Among the highlights: the sale of the company’s 467-MW portfolio of 25 solar plants in 14 states; the acquisition of a 25% share of the Ocean Wind offshore wind project under development on the New Jersey coast by Denmark-based Ørsted; and the announcement of a new goal to reach net-zero emissions by 2030, 20 years earlier than its previous target. The company also submitted nine proposals into the joint solicitation by the New Jersey Board of Public Utilities and PJM for transmission project proposals that will facilitate offshore wind projects.

Longer-term Subsidies

Izzo said he is looking to avoid the demands of applying every three years for subsidies to support the three nuclear generating plants — Hope Creek nuclear power plant and Salem 1 and Salem 2 — operated by PSEG in South Jersey, under the zero-emission certificate (ZEC) program. The approval in April of subsidies worth $300 million, the second three-year subsidy awarded to PSEG under the program, triggered sharp criticism from the New Jersey Division of Rate Counsel, the state’s consumer advocate, and environmental activists, who questioned whether the utility needed the funds to keep the generators operating. (See NJ Nukes Awarded $300 Million in ZECs.)

Izzo said he would like to see a “longer term” incentive program developed at the state level, and he is hoping for talks to resume at a federal level about awarding tax credits that would help support the operators of nuclear plants, such as PSEG.

“In the last four years, we had the creation of the legislation for the ZECs, and we had two rounds of ZECs,” he said, likening such a schedule to “sort of being masochists.”

“My sense from policy leaders — elected officials, regulators, key staff members — is we need these plants to run, at least until 2050,” he said. “The reality is, people have already expressed an interest in our nuclear plants. And they are outstanding assets. The issue is, how do you firm up the longer-term economic treatment beyond a three-year time frame?”

The U.S. Department of Energy last week invited public comment on the $6 billion Civil Nuclear Credit Program — funded under the Infrastructure Investment and Jobs Act — that will allow owners and operators of commercial nuclear reactors at risk of closure to competitively bid on credits to keep them in operation. (See DOE Launches $6B Nuke Credit Program.)

Izzo said the company also is in discussions that could lead to an increase in its offshore wind portfolio.

“We have a series of conversations underway that are related to Ocean Wind II, Skipjack [and] potential further upside of Ocean Wind I,” he said. The 1,148-MW Ocean Wind II project was one of two projects awarded leases in New Jersey’s second offshore wind solicitation in June. Ørsted, the project developer, also is developing two projects under the Skipjack name off the Maryland and Delaware coast. (See NJ Awards Two Offshore Wind Projects.)

Izzo said the company’s “initial early caution” about investing in offshore wind projects has diminished, in part because of increased understanding of the “commitment of other states in the development of supply chain [and] some of the regulatory hurdles that have been eased by virtue of some state actions and some federal actions.”

PSEG subsidiary PSEG Renewables is one of 25 companies eligible to bid in the auction underway this week for six leases in the New York Bight in a solicitation held by the U.S. Bureau of Ocean Energy Management.

Earnings

PSEG reported a net loss of $648 million (‑$1.29/share) for 2021, compared to net income of $1.905 billion ($3.76/share) for 2020. Non-GAAP operating earnings for 2021 were $1.853 billion ($3.65/share), compared to $1.741 million ($3.43/share) for 2020.

The loss in 2021 was from a pre-tax impairment charge of about $2.7 billion that stemmed from the sale of the fossil plants, the company said.

The company reported net income for the fourth-quarter of $445 million ($0.88/share), compared to net income of $431 million ($0.85/share) in 2020’s fourth quarter. Non-GAAP earnings for the quarter were $352 million ($0.69/share), compared to fourth-quarter non-GAAP earnings of $392 million ($0.65/share).

Posted on

‘Beautiful Symphony’ or Bust on Order 2222, Advocates Say

Distributed generation advocates and developers are frustrated with ISO-NE’s plan for complying with FERC Order 2222, but they say there are big prospects for improvement in a process that’s only halfway done.

The grid operator’s compliance filing, submitted to FERC earlier this month (on the fitting date of 2/2/22), would create new market participation models aimed at meeting federal regulators’ mandate to allow aggregated distributed energy resources to take part in its wholesale markets. (See NEPOOL PC Approves Tariff Changes for Aggregated DERs).

Industry representatives, speaking at the RE+ Northeast conference this week, said it simply fails to meet that goal.

“For front-of-the-meter DERs, I think ISO’s proposal has some benefits. For behind-the-meter DERs, it’s problematic. We don’t really think it accomplishes a whole lot, unfortunately,” said Nancy Chafetz, senior director of regulatory and government affairs at CPower Energy Management.

The proposal doesn’t allow resources behind a customer’s meter to participate directly in the market unless they have sign off from distribution utilities, which are unlikely to give the OK in the near term, Chafetz said.

Activating behind-the-meter DERs in the market could be valuable because there are whole fleets of them, including batteries, electric vehicles, hot water heaters and other devices in customers’ homes ready and waiting to be deployed to help stabilize the grid.

“If you’re a grid operator, emergencies don’t only happen between 4 p.m. and 8 p.m. every day on a weekday,” said Michael Macrae, senior director of regulatory affairs for ENEL North America. “Sometimes they happen at 10 in the morning on a Tuesday. And there’s no way to call all the [DERs] and say, ‘The person who uses you would be totally clueless if you just stopped for an hour.’”

The ISO-NE filing fails to capture that flexibility, he said.

“We would love to have all these resources be available for ISO dispatch and earn capacity market revenues for providing that service,” Macrae said.

Still Time on the Clock

The good news, say advocates, is that ISO-NE’s filing to FERC — and its counterparts from other regions — were just part of the conversation and not the end of it.

“Even though we were disappointed in all of the compliance filings that came in, I think we need to acknowledge that this is an ongoing conversation that will need to be iterative even after FERC rules,” said Chris Rauscher, senior director of market development and policy at Sunrun.

For example, there are rules outside of 2222’s scope that would prevent some resources from bidding into the market, like PJM’s must-offer rule, which requires resources participating in the capacity market to also bid into the energy market.

Advanced Energy Economy has been one of the most vocal critics of ISO-NE’s 2222 filing and is expected to protest it at FERC.

The trade group’s managing director Jeff Dennis said this week that commission staff have been asking detailed questions about previous filings from California and New York.

“That said to me that the commission is digging in and looking very carefully at these compliance filings,” he said.

Potential for a ‘Beautiful Symphony’

Despite their worries about the regulatory process, industry advocates see a bright future for DERs on the horizon.

“Bringing all of these DERs in aggregation to respond to wholesale markets, in my mind, is the biggest opportunity I’ve ever seen in my career for unlocking flexibility on the demand side,” Dennis said.

He gave the example of school bus electrification, which could produce “incredible” resources for flexibility.

“In five years, if FERC and the markets get it right, it will be a beautiful symphony every day,” Rauscher said.

Posted on

Japan Working to Make Hydrogen a Transportable Energy Commodity

The Biden administration’s $9.5 billion bet on hydrogen becoming an industrial and transportation fuel in the future may come down to how easily the colorless and odorless gas can be transported.

Mitsubishi has been working on that problem for years and believes it now has a solution: store the gas in a “carrier,” a common industrial organic compound such as methylcyclohexane (MCH). A liquid at ambient temperatures, MCH can be handled like gasoline and moved around the world in tankers and pipelines.

Working in a consortium with other Japanese companies, Mitsubishi proved the concept in 2020 with a project in which green hydrogen was repeatedly produced in Brunei, a small sun-drenched country on the island of Borneo and shipped to Japan in ordinary tankers.

Kiichiro Fujimoto, general manager of Mitsubishi’s Infrastructure Solutions Department, explained the process and Japan’s goals to cut carbon emissions in half by 2030 during a webinar produced Thursday by the D.C.-based Center for Strategic and International Studies.

Fujimoto explained that the hydrogen was mixed with toluene, a common solvent and degreaser, creating the liquid MCH.

“MCH is very chemically stable, [exhibits] a very minor loss during the long-term storage and long-distance transportation. It’s easy to handle,” he said. When the hydrogen was recovered from the MCH in Japan, the solvent was shipped by tanker back to Brunei.

Mitsubishi and its partner companies in the Brunei project believe that the MCH method can be used to ship hydrogen from Australia and Chile, two countries that are planning to make hydrogen with renewable power. (See Global Hydrogen Conference Reveals Plans to Ship Sunshine.) Middle Eastern companies are also planning to produce green hydrogen, which could be shipped to Europe as well as Japan.

Scale — both in production and in use — is the key to making hydrogen affordable, Fujimoto said.

“Here is the important part: In order to support this billion-[dollar]-size project, we need a very reliable hydrogen producer, a very reliable hydrogen buyer, and we need a very reliable hydrogen carrier technology and a company that operates all these operations,” he said, adding that his company is working on business opportunities in Singapore and Europe.

Snam, an Italian energy infrastructure company, is working to create a hydrogen supply chain not only in Italy but across Europe to move the hydrogen once it arrives from overseas.

Giovanna Pozzi, in charge of renewables and power supply for hydrogen at Snam, said the company has been blending hydrogen with natural gas in ongoing tests of its pipelines.

In a controlled test, she said the company delivered gas containing 10% hydrogen to a glass maker and a bakery. Neither business had any problems, nor did the pipelines, she said.

“We have been able to define the new technical standards for the injection of hydrogen into our pipes. We’re moving to different countries into Europe because we are teaming up with the 23” other companies, she said. “We are exchanging information with a very ambitious aim: the creation of the first European hydrogen backbone.”

The hydrogen-dedicated network would be about 40,000 km, she said, of which 70% would be repurposed existing gas lines and 30% new construction. (See Roundtable Looks at Storage, Hydrogen to Decarbonize Northeast.)

But to make this work, the 23 companies need new common, European-wide policies and regulations, which currently do not exist, she said.

“I think that the key success factors that we are talking about are technical constraints and standards, new standards for these gases. And then the regulation and funding support,” she said.

Neil Navin, vice president for clean energy innovations at Southern California Gas (NYSE:SRE), said his company has also worked on blending and sees aggregating demand for hydrogen as important to moving to large-scale production and use.

Pointing out that California has a significant industrial base that could use hydrogen in place of hydrocarbons.

“The key to electrolytic [green] hydrogen is to put the solar panels in the place where the sun is most intense, and most often … making sure that you can situate your renewables in those locations, co-produce hydrogen and then transport that hydrogen into the demand centers,” he said. “That really dictates the topology of transportation.” (See related story, SoCalGas Proposes Hydrogen Pipelines.)

Navin added that the hub concept advocated by the Biden administration — producing a lot of hydrogen in an area abundant in renewables or natural gas — just makes sense financially.

“We found that there is a real logic to looking for the areas of highest renewable penetration for the source of hydrogen,” he said, rather than producing it locally.

“It seems counterintuitive, but once you look at the math, the economics become more apparent. So, what I think you’ll find in each region, especially in the United States, is that demand will likely not move, [and] the factory will stay where it is.

“The power plant will stay where it is. People will not move to the renewables; you will have to move the hydrogen to them.”

Posted on

Entergy Regulators Ask FERC to Settle Grand Gulf Dispute

Three regulatory bodies are demanding answers on FERC’s apparent delay in addressing a complaint over the management of a southwestern Mississippi nuclear plant.

Attorneys for the Louisiana Public Service Commission, Arkansas Public Service Commission and Council of the City of New Orleans filed a motion Monday to again request FERC schedule a hearing on a complaint alleging maladministration at the 1,428-MW Grand Gulf nuclear station (EL21-56).

The regulators asked for a remedy for Entergy subsidiary System Energy Resource, Inc.’s (SERI) “significant customer harm arising from years of imprudent operations and mismanagement.” They pointed out that their original complaint was filed almost a year ago, on March 2, 2021.

“Nearly every other complaint filed in the commission’s docket year 2021 has been acted upon by the commission in some manner, yet this complaint is still pending initial commission review,” lawyers for the regulators wrote.

The regulators reminded FERC that it has a duty under the Federal Power Act to act swiftly on complaints and said the D.C. Circuit Court of Appeals “has expressed dismay at the lengthy time lags experienced by litigants before the commission.”

“What constitutes a ‘reasonable’ time to conclude a controversy may vary with the circumstances of each case; however, it is not reasonable for the commission to take over a year to evaluate whether or not a complaint merits further investigation,” the regulators said, adding that they aren’t aware of any reason for FERC’s delay.

The bodies said they have supplied the commission with supporting evidence and sworn affidavits that could be used in a FERC investigation.

Grand Gulf station is the nation’s largest nuclear reactor. Entergy sells the output at wholesale to its Arkansas, Louisiana, Mississippi and New Orleans subsidiaries.

Last year’s complaint described “imprudent operation” and “subpar performance” at Grand Gulf and sought refunds and rate reform on more than $1 billion in costs passed on to Entergy customers.

The regulators tapped Critical Technologies Consulting (CTC) to investigate the plant’s operations from 2012 to 2020. They said CTC uncovered costly safety issues and substandard output performance. They also said Entergy inappropriately used an outdated economic analysis in 2012 when it decided to undertake approximately $800 million worth of construction to bulk up the plant’s capacity.

The Louisiana PSC said the uprate work paradoxically led to diminished electricity production from Grand Gulf. Entergy customers often found themselves paying for the plant’s full fixed investment and operating costs in addition to replacement energy sourced from other plants, the New Orleans City Council said. The regulators said Grand Gulf’s frequent outages drove shortages and upped energy prices in the MISO markets.

The Nuclear Energy Institute’s data indicates Grand Gulf is the worst-performing nuclear plant in the nation, with a 66.3% capacity factor from 2018 to 2020. The plant’s last-place finish is well below the 77.9% capacity factor of Michigan’s Fermi 2, the other least-reliable unit.

The regulators estimate that their ratepayers are owed about $361 million for the added expense of Grand Gulf outages from 2016 to 2020. They also want the 2012 upgrades investigated and possibly refunded.

“We promised New Orleanians that we would hold Entergy accountable over their responsibility to provide reliable, affordable power to their ratepayers,” New Orleans Council President Helena Moreno said last year. “Grand Gulf is the single largest energy resource for the city of New Orleans, and we need it to be operating safely, at full capacity, and at a reasonable cost. We are asking FERC to help us get that plant running efficiently again as well as seeking refunds to make it right by our people.”

“Entergy customers deserve a full look at the potential imprudent management of Grand Gulf and, eventually, appropriate refunds if it is found that Entergy passed unnecessary costs onto those customers,” then-Louisiana PSC Chairman Craig Greene said.

Entergy said it doesn’t see anything amiss with the yearlong wait.

“While we don’t typically comment on pending litigation, this is a large, complex case, and we do not believe there has been any undue delay in setting the case for hearing.  Further, we dispute the allegations that we have not prudently operated and managed Grand Gulf. In fact, this past year, Grand Gulf achieved all-time plant records for both gross generation and net generation in megawatt-hours,” Entergy spokesperson Mike Bowling said in an emailed statement to RTO Insider.

Bowling said in 2021, Grand Gulf’s net generation was nearly 12 million MWh, while its gross generation surpassed the 12 million MWh mark.

Entergy had not responded to requests for comments at press time on the year-long delay or how it plans to react should FERC set a hearing in the matter.

Grand Gulf’s unit power sales agreement with Entergy’s member companies is at the heart of another ongoing FERC complaint (EL20-72). In that docket, Louisiana, New Orleans, Arkansas and Mississippi regulators have accused Entergy and SERI of massaging accumulated deferred income tax numbers to overcharge customers for Grand Gulf’s sale-leaseback arrangement and recovering in rates through the sales agreement the costs of lobbying, image advertising and private airplane use.

In recent testimony, Entergy Vice President of Regulatory Services Joshua Thomas characterized the proceeding as a “kitchen sink” complaint, covering “a wide range of complex subject areas over a 30-year time period.” Thomas said the retail regulators “claims are vague, and the requested relief is undefined.”

Entergy maintains it doesn’t include below-the-line costs in ratemaking and that no over-collection occurred.

Posted on

FERC Approves PJM Capacity Auction Date Changes

FERC on Tuesday approved PJM’s revised schedule for the upcoming Base Residual Auctions (BRAs), incremental auctions and associated pre-auction deadlines through the 2026/27 delivery year (EL19-58).

PJM’s updated schedule proposed conducting the 2022/23 third incremental auction (IA) beginning on Monday, as scheduled, and continuing to use the forward-looking energy and ancillary services (E&AS) offset, as it was used in the 2022/23 BRA.

The 2022/23 BRA, originally scheduled for January, will now take place on June 8; the 2024/25 BRA moves from August to December; the 2025/26 auction moves from February 2023 to June 2023; and the 2026/27 auction moves from August 2023 to November 2023. The 2027/28 BRA will be back on schedule in May 2024.

The first and second IAs are canceled for the 2023/24, 2024/25 and 2025/26 BRAs, and the first IA is canceled for the 2026/27 BRA.

In a remand order issued Dec. 22, FERC reversed its approval of PJM’s forward-looking E&AS offset. The commission said PJM must now revert to the previous, backward-looking offset. (See FERC Reverses Itself on PJM Reserve Market Changes.) The commission said it recognized PJM would need to delay the BRA to implement a revised E&AS offset, a key variable in calculating the net cost of new entry for resources in capacity auctions.

In the remand order, the commission directed PJM to submit a compliance filing proposing a new schedule for the 2023/24 delivery year and subsequent BRAs. PJM updated the schedule in the middle of January and made an official filing on Jan. 21. (See PJM Reveals Preliminary Capacity Auction Timeline.)

On Tuesday, FERC said it found that PJM complied with its directive by filing an appropriate revised schedule and that it included “sufficient justification” for the schedule.

“PJM reasonably minimizes the delay of the 2023/24 BRA by proposing to revise only pre-auction deadlines impacted by the E&AS offset revision and the general delay of the auction, which necessitated the use of an updated load forecast,” FERC said in its order. “PJM also reasonably proposes to allow capacity market sellers to update only the E&AS offset portion of their unit-specific requests. We agree with PJM that this approach will allow for administrative efficiencies by not requiring duplicative information to be resubmitted, potentially allowing PJM to avoid unnecessary delay.”

The commission agreed with PJM’s proposal to eliminate some of the IAs. It also said it found it “reasonable” for the RTO’s proposal to retain limited discretion of up to 10 business days to set the specific deadlines associated with any pre-auction activities.

“We agree with PJM that it would be cumbersome and administratively inefficient to seek further amendments to the auction timelines for minor adjustments to the deadlines,” FERC said in its opinion. “However, we recognize PJM’s commitment to post the specific dates of pre-auction activities no later than eight months prior to the commencement of any associated BRA in order to ensure that all market participants are aware of the relevant deadlines.”

Danly Concurrence

In a separate concurrence, Commissioner James Danly said he agreed with the updated schedule, stating that PJM’s capacity auctions “have been delayed for far too long.” Auctions that have historically been looking three years ahead “have had their periodicity reduced to a year or less,” he said

Danly said the commission in its role as regulator “bears most of the blame for the sorry state of PJM’s auction schedule,” but he also faulted the RTO for the auction delays. He said PJM’s filing made to “eviscerate its minimum offer price rule” in the summer and another auction delay it requested in September contributed to the limited timing of the auctions.

“This last delay is particularly galling,” Danly wrote. “Given its role in causing and requesting auction delays, PJM’s call for the commission to ‘expeditiously’ and ‘promptly issue an order and provide much needed market certainty’ is … brazen.”