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November 17, 2024

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FERC Approves $147K Penalties in SERC, RF

FERC approved penalties on Thursday totaling $147,000 against University Park Energy of Illinois and Broad River Energy of South Carolina, as part of a package of settlements concerning violations of NERC’s reliability standards filed in NERC’s monthly spreadsheet Notice of Penalty (NP23-11).

The commission indicated in a filing that it would not further review the settlements that the utilities reached with ReliabilityFirst and SERC Reliability, respectively, leaving the penalties intact. FERC also approved a settlement concerning an infringement of NERC’s Critical Infrastructure Protection (CIP) standards filed along with the SNOP on Jan. 31 (NP23-10); the utility and regional entity involved were not identified, in keeping with NERC and FERC’s policy on CIP violations.

Broad River Settles Over Communication Issues

SERC’s settlement with Broad River stems from violations of VAR-002-4 (Generator operation for maintaining network voltage schedules) and PRC-005-1b (Transmission and generation protection system maintenance and testing). The settlement carries a $115,000 penalty.

Broad River brought the VAR-002-4 violation to SERC’s attention via a self-report, though SERC noted that the utility submitted the report only “after receiving notice of an upcoming spot-check” and the RE thus did not consider the report a mitigating factor. Similarly, mitigating credit was denied for the report of the PRC-005-1b violation because Broad River “reported the violation through the self-certification process.”

According to the filling, SERC had planned the spot-check to begin Oct. 21, 2019, and asked Broad River ahead of time for proof of VAR-002-4 compliance between Aug. 1, 2015, and Oct. 18, 2019. The utility ran a complete voltage profile for the entire period, matching it against the generator voltage schedule provided by the transmission operator (TOP); requirement R2 of VAR-002-4 requires generator operators to maintain the TOP’s schedule or inform the TOP why it cannot be met.

Examining the voltage schedules, Broad River identified 419 events in which its generator facility “was outside of the voltage schedule for 30 minutes or longer.” Operators only notified the TOP about 57 of these excursions, a violation of the standard.

SERC determined that the violation began on Aug. 5, 2015 — the first time the utility experienced an excursion and failed to notify the TOP — and ended March 7, 2019, the last time such an event occurred. The RE attributed the violation’s cause to “inadequate communication between third-party plant and asset manager and senior management, and [between] plant management and employees responsible for compliance.”

The violation of PRC-005-1b — and its successor PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) — relates to requirement R2 of the earlier standard and R3 of the latter, which describe the minimum maintenance activities timelines for protection systems and the acceptable evidence for completion of the activities.

Broad River informed SERC on June 11, 2020, that it could not confirm it had completed all required testing under PRC-005-6. The utility said that while the previous operator of its generation facility had a schedule for performing the tests, Broad River did not have documentation that they actually had been done.

To assess the extent of the noncompliance, Broad River performed a complete walkdown of its facility and found 435 devices that were included under the standard’s requirements but for which it did not have proper evidence of testing. In some cases, the lack of supporting documents began as early as Dec. 27, 2012, the date it registered as the operator of the facility; as a result, SERC determined that the violation spanned the earlier standard as well.

To address the noncompliance, the utility tested all devices for which it had no records; the final test was completed on Nov. 5, 2021. SERC concluded that the cause of this violation — as with the VAR-002-4 infringement — was organizational silos that prevented adequate communication between parties responsible for compliance.

The RE said it aggravated the penalty for both infringements based on “the number of instances and long duration for the violations [which] indicated the prior management’s ignorance of the violations.” However, it did award mitigating credit for cooperation and timely responses, and because Broad River agreed to settle, “thereby avoiding a hearing on this matter.”

RF Faults Utility for Maintenance Schedule Slips

University Park’s $32,000 settlement with ReliabilityFirst involved PRC-005-2 (i) (Protection system maintenance). Requirement R3 of the standard establishes the schedule by which transmission owners, generation owners, and distribution providers must maintain their protection system components.

The utility informed ReliabilityFirst on May 15, 2020, that it had discovered, as part of a third-party review of its NERC compliance program, that “not all components were being maintained/tested, or maintenance and testing activities were not being documented, as required.” The problem encompassed multiple classes of equipment at its generator facility.

University Park attested that the violation began on Oct. 1, 2015, when the facility was required to comply with the standard, and continued until May 21, 2021, when it completed its mitigating activities. These included developing a preventative maintenance work plan to “identify the maintenance required and its frequency for all applicable equipment.” The utility also reviewed the violation with all applicable staff members.

The RE said it awarded mitigating credit to the utility for coming forward voluntarily because it “seeks to encourage this type of self-reporting.” However, it also noted previous compliance issues with PRC-005-1, saying this should serve as an aggravating factor in the penalty because the utility “failed to sustain the mitigating actions … in response to those prior issues.”

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DOE Opens IIJA Nuclear Credit Program to Recently Closed Plants

A closed nuclear plant in Michigan could be eligible for federal funding to help it reopen under new guidelines for the second round of the Civil Nuclear Credit Program that the U.S. Department of Energy released Thursday.

Authorized by the Infrastructure Investment and Jobs Act, the program received $6 billion to be used to help existing plants at risk of closure stay online. The first round of funding was limited to plants that had publicly announced their intention to close, ultimately awarding up to $1.1 billion to the Diablo Canyon nuclear plant in California, which had been scheduled to close in 2025.

The plant has now received permission from the Nuclear Regulatory Commission to stay open beyond that date. (See related story, NRC OKs Exemption to Keep Diablo Canyon Running During License Renewal.)

The second round, which could provide up to $1.2 billion in credits, will be open to “owners or operators of nuclear reactors that are at risk of closure by the end of the four-year award period, including such reactors that ceased operations after Nov. 15, 2021,” according to a DOE press release.

The four-year award period runs from Jan. 1, 2024, to Dec. 31, 2027. The Nov. 15, 2021, qualifying date is the day President Biden signed the IIJA into law. The 800-MW Palisades Nuclear Generating Station on Lake Michigan, west of Kalamazoo, is the only U.S. nuclear plant that has closed since that date.

“Preserving the domestic nuclear fleet is critical to reaching America’s clean energy future,” Energy Secretary Jennifer Granholm said in the press release. “Expanding the scope of this [IIJA] funding will allow even more nuclear facilities the opportunity to continue operating as economic drivers in local communities that benefit from cheap, clean and reliable power.”

The U.S. nuclear fleet now includes 92 plants that provide about 20% of the country’s electric power and 50% of its carbon-free power. Thirteen other plants, including Palisades, have closed in the past decade, according to a recent report from the National Association of Regulatory Utility Commissioners.

Many plants still in operation were built in the 1970s and 1980s, and either face decommissioning or must be recommissioned to extend their licenses. They have also faced competition from cheap natural gas and renewables that have made them economically difficult to keep in operation.

Illinois, New Jersey and New York now provide zero-emission credits to help keep their nuclear plants online.

Dollars for Nukes

Maintaining and expanding the U.S. nuclear fleet has become a critical part of the Biden administration’s strategy for decarbonizing the U.S. electric grid by 2035. In addition to the CNC program, the IIJA includes close to $2.5 billion for DOE’s Advanced Reactor Demonstration Program to support the deployment of two advanced reactors within a seven-year time frame.

The Inflation Reduction Act offers nuclear developers either a 30% investment tax credit or $30/MWh production tax credit, according to the NARUC report.

DOE’s Loan Program Office has also provided ongoing support for the two reactors still waiting to go online — six years late and extremely overbudget — at Southern Co.’s Vogtle plant in Georgia. The plant received a total of $12 billion in loan guarantees: $8.3 billion during the Obama administration and another $3.7 billion during the Trump administration. (See Making the Case for Nuclear at NARUC.)

Echoing Granholm, Matt Crozat, executive director of of strategy policy development at the Nuclear Energy Institute, welcomed the new CNC guidelines, saying they would create “more opportunities for the current fleet to apply to for the [program].”

The CNC and other federal funding will, Crozat said, “provide a strong financial foundation for the continued investment into these nuclear plants.”

The CNC is a more targeted program, with $1.2 billion in credits per year for five years, beginning in 2022 and ending in 2026. According to a DOE fact sheet, to qualify for the program, an owner or operator must “demonstrate that the reactor competes in a competitive electricity market and that DOE, to the maximum extent practicable, must determine that a reactor is projected to cease operations due to economic factors, that air pollutants will increase if the reactor retires and that the U.S. Nuclear Regulatory Commission has reasonable assurance that the reactor will operate consistent with its current licensing basis and that it poses no significant safety hazards.”

For last year’s funding cycle, DOE required applicants to have publicly announced the closure of a plant and provide official documentation such as a filing with the NRC or Securities and Exchange Commission. This time around, the guidelines simply require applicants “to provide a narrative explanation, with supporting documentation, of the likelihood that a nuclear reactor operating as of Nov. 15, 2021, is projected to close (or has ceased operations).”

Qualified applicants also submit bids for the amount of credits they are seeking, based on the difference between a reactor’s costs to operate and its revenues. Credits are paid annually at year-end, with the amount depending on a reactor’s actual output. For example, Diablo Canyon will qualify for amounts ranging from $266 million to close to $289 million per year for the next four years, according to DOE figures.

Palisades changed owners just as it was closing, with former owner Entergy selling the plant to Holtec International, a company specializing in providing parts for nuclear plants. Holtec applied for CNC funding in the first round but was turned down.

In a Dec. 19 Facebook post, the company announced its determination to reapply for the second round of CNC funding.

“The repowering of Palisades is of vital importance to Michigan’s clean energy future,” it said. “As Michigan transitions from fossil fuel generation to renewables and emerging advanced technologies, baseload nuclear generation is an essential backstop. Based on the supportive feedback we have received, Holtec will be reapplying for the next round of funding through the U.S. Department of Energy’s Civil Nuclear Credit Program to support the repowering of Palisades.”

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Alvarado Withdraws from Md. PSC Nomination

A representative of the gas industry that Maryland Gov. Wes Moore (D) recently nominated to serve as one of the state’s key utility regulators withdrew his name from consideration on Tuesday, heading off what was shaping up as an adversarial confirmation process in the Senate.

In a statement issued by the governor’s office, Juan Alvarado, senior director of energy analysis for the American Gas Association, said he had decided to withdraw his nomination to the Maryland Public Service Commission “for personal reasons.” A spokesperson for Moore confirmed that the governor had neither requested nor in any way pressured Alvarado to stand down.

Alvarado was one of two PSC nominations Moore sent to the Senate on Feb. 17 as part of his “Green Bag” appointments. The governor also nominated Frederick H. Hoover Jr., assistant people’s counsel in the Office of the People’s Counsel, to chair the commission after the term of the current chair, Jason Stanek, expires in June. (See Moore Names Consumer Advocate to Head Md. PSC.)

While Hoover, a former board chair of the League of Conservation Voters, was seen as a good choice to lead the commission, questions and concerns about Alvarado’s connections to the gas industry began piling up soon after his nomination.

In addition to his work with the AGA, Alvarado spent 12 years at the PSC, seven of them as director of its Telecommunications, Gas & Water Division, according to his resume on LinkedIn.

In an interview with Inside Climate News, Kim Coble, executive director of the Maryland League of Conservation Voters, said having a gas industry official on the commission “could present a challenge to the PSC’s efforts to advance utility and transportation services while also respecting the significant and unique role the commission plays in advancing the state’s climate goals and specifically the governor’s 100% clean energy goal.”

Maryland’s Climate Solutions Now Act (SB 528), passed by legislature last year, commits the state to a 60% drop in greenhouse gas emissions by 2031 and to net-zero emissions by 2045. As a candidate, Moore also committed to working toward a 100% clean electric grid in the state by 2035.

“Placing someone from the gas industry at [the PSC] could jeopardize the governor’s promise to take on climate change,” Josh Tulkin, director of the Maryland chapter of the Sierra Club, told The Washington Post. “Mr. Alvarado is completely the wrong person for the job.”

Maryland People’s Counsel David Lapp told the Post, “The gas utilities in Maryland are continuing to invest heavily in gas infrastructure. So, it’s critical that we have decision-makers at the Public Service Commission that can fairly and objectively evaluate those investments to determine whether they are best for customers, as well as best for furthering the state’s climate goals.”

The debate on Alvarado also spilled over to Twitter, where R. Scott Everngam, a former PSC staffer and FERC subject matter expert, said, “Moore should have stood his ground and defended” Alvarado.

Travis Kavulla, former president of the National Association of Regulatory Utility Commissioners, agreed, saying, “You should probably have on your PUC someone who really knows the mission-critical issues of gas utilities — that is ‘especially’ true if your gas policy isn’t just ‘straight course ahead.’”

Tough Questions

But even with Moore’s support, Alvarado would have faced tough questions in the Maryland Senate.

Sen. Will Smith (D), of Silver Spring, had said he would seek to put a hold on the nomination, citing a natural gas explosion at an apartment building in his district in 2016, when Alvarado was at the PSC.

As reported in Maryland Matters, the explosion at the Flower Branch Apartments in Silver Spring resulted in seven deaths, including two children. The explosion was caused by a faulty mercury gas regulator, commonly found in houses built before 1960. An investigation found that Washington Gas, the local utility, had fallen behind in its plans for replacing the equipment, and questions were raised about whether the PSC had also been lax in pushing the utility to expedite the work.

Smith had said he wanted to question Alvarado about his role in overseeing the equipment upgrade and the investigation following the explosion.

The nonprofit Environmental Law Institute was also critical of the nomination, citing Alvarado’s public statements in support of natural gas.

In a recent promotional video for the AGA, Alvarado says that the replacement of coal with gas has been responsible for a major reduction in U.S. greenhouse gas emissions. “It’s going to be an integral part of further reducing emissions in the future, to the point where I think it can one of the paths to zero net emissions,” he says.

ELI also pointed to Alvarado’s presentation at a NARUC conference in 2022, calling for more “regulatory support” for natural gas.

“We need to educate everyone about the benefits of resilience on the gas system, and those benefits expand to the energy systems … how that is critical to their well-being,” he said.

In his statement withdrawing his nomination, Alvarado emphasized his experience at the PSC.

“My 12 years of service to Maryland as a member of [the PSC] gave me the highest reverence for the work it does each and every day to address climate change, improve service to ratepayers and ensure families have access to reliable telecommunications, gas and electricity,” he said.

“Climate change is the fight of our lives, and I believe that we have real and substantive challenges to meet Maryland’s goals while ensuring continuous and equitable service at fair rates. Those challenges mean all stakeholders need to be at the table executing the state’s vision towards a sustainable future.”

Who’s Next?

In a statement released with Alvarado’s, Moore also praised Alvarado’s PSC experience and affirmed his administration’s commitment to climate action.

Alvarado’s “deep understanding of the Public Service Commission was knowledge that would have served Maryland well,” Moore said. “As we look ahead, my administration is fully committed to achieving Maryland’s bold and necessary climate, energy and resilience goals. Our nominees to the Public Service Commission will be aligned with our administration’s goals, and we will work in partnership throughout this confirmation process to move Maryland forward.”

Providing that Hoover is confirmed, Moore now has two PSC seats to fill after rescinding the nominations of Commissioners Patrice Bubar and Odogwu Obi Linton, both of whom were appointed by former Gov. Larry Hogan but have remained unconfirmed. They were among the 48 Hogan appointees that Moore rescinded, with no explanation, in a Jan. 23 letter.

Environmental groups are already lining up with suggestions. According to the Post, the LCV’s Coble is supporting Scott Hempling, a FERC administrative law judge and an expert on public utility law. Mike Tidwell, director of the Chesapeake Climate Action Network, would like to see a nomination for Meghan Conklin, a former energy adviser to U.S. Sen. Chris Van Hollen (D-Md.). Conklin also served as a deputy assistant secretary for transmission planning at the U.S. Department of Energy during the Obama administration.

Bubar and Linton will continue to serve on the PSC until their replacements are confirmed and sworn in.

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ACE NY Lays out Legislative Priorities for Energy Transition

ALBANY, N.Y. — Key policy and funding decisions being made now will shape New York state’s clean energy transition, but regardless of the specifics, a significant workforce investment will be needed, advocates said Wednesday.

The Alliance for Clean Energy New York (ACE NY) held a briefing on its legislative priorities as state budget negotiations intensify and invited speakers from two organizations that are training some of the estimated 200,000 new workers needed for the transition.

A handful of the state’s 213 lawmakers were in the audience for the event, held a month shy of the statutory deadline for passage of the 2023-2024 state budget.

Gov. Kathy Hochul presented her plan Feb. 1. A series of legislative budget hearings followed, and Senate and Assembly leaders are expected to produce their counterproposals soon. Closed-door negotiations will produce a final budget that not only allocates a pile of money — Hochul’s proposal totals $227 billion — but codifies a range of policy decisions that might face tougher prospects for passage if voted on separately.

ACE NY, which advocates for clean energy on behalf of business and organizations in that field, is just one of many of the advocates lobbying for its priorities as the details are hammered out this month.

But with New York pressing one of the most ambitious climate protection plans of any state, and being one of the most expensive states in which to carry such plans out, the details will impact residents’ wallets and quality of life for decades to come.

ACE NY Executive Director Anne Reynolds said transmission constraints and the often lengthy review process facing renewable power developers are key problems to address if the state is to meet its goals.

Of the 137 projects awarded contracts by the New York State Energy Research and Development Authority since 2017, only 20 are operational, and they are small, representing just 3% of the combined 13.62 GW capacity of the projects. The 15 projects that were canceled make up 6% of the total.

“NYSERDA’s been doing an excellent job awarding these contracts on an accelerated basis and the projects are creeping their way through this process, but it’s a long one and we have a long way to go,” Reynolds told attendees.

Among ACE NY’s 2023 legislative priorities is a directive that the New York Power Authority propose projects to ease the top three transmission-constrained zones, as identified by NYISO; speeding up the process by which developers mitigate impacts on endangered and threatened species; and the exclusion of alternative energy production facilities from what the organization calls a duplicative permitting process under Sections 68-70 of the state Public Service Law.

“In the budget negotiations, the thing that we’re watching the most are the cap-and-invest policy, the Build Public Renewables [Act] and the all-electric buildings,” Reynolds told RTO Insider after the meeting. If all three are in both the Assembly’s and Senate’s budgets, she said, the measures will have momentum going into final negotiations. “Then it’s game on with respect to those pieces.”

ACE NY is opposed to the governor’s version of Build Public Renewables because it would give a renewable energy development role to NYPA. This would put NYPA in unfair competition with the private sector, when it should instead be concentrating on transmission development, the organization argues.

Next Generation

Vincent Albanese of the New York State Laborers’ Organizing Fund highlighted workforce development as another potential sticking point.

Officials mapping out New York’s energy transition estimate that more than 200,000 new jobs will be created in the process, many of them in skilled trade. The scoping plan for the Climate Leadership and Community Protection Act of 2019 repeatedly flags the need for workforce development.

Vincent Albanese 2023-03-01 (RTO Insider LLC) FI.jpgVincent Albanese, New York State Laborers’ Organizing Fund | © RTO Insider LLC

Aside from the effort of training workers, there is also the task of recruiting people in a state that is losing population.

Albanese displayed a map showing New York state’s population centers: most of them downstate, some spreading north along the Hudson River and west along the Erie Canal. Then he overlaid a map of renewable energy projects: most of them upstate, many of them dozens of miles from the nearest population center.

“One of the biggest challenges that we’re facing is most of these jobs, at least on the generation side, are located in parts of New York that are incredibly rural and not densely populated,” he said. “People have major challenges getting to these jobs, dealing with childcare [and] all sorts of transportation issues.

“If we can’t solve this problem, none of this happens,” he added.

Many new green jobs will of course be in those population centers: electrifying homes and transportation, for example. But other challenges exist there.

New York is targeting 35 to 40% of the benefits of the energy transition to disadvantaged communities, including through job training, but legislation would not erase the legacy of those disadvantages.

Jennifer Lawrence 2023-03-01 (RTO Insider LLC) FI.jpgJennifer Lawrence, Social Enterprise And Training Center | © RTO Insider LLC

Jennifer Lawrence, executive director of the Social Enterprise and Training (SEAT) Center in Schenectady, said her organization takes on these challenges. Its young clients will not emerge from the YouthBuild program as journeyman carpenters, for example, but they will have the hard skills to enter the workforce and the soft skills to advance in the workforce.

SEAT has been collaborating with the laborers union, which has training centers in the Albany-Schenectady region, and with East Light Partners, which has a 20-MW solar project nearby, to acclimate young workers to the industry and the labor organizations that work in it.

“It’s also going to build a sense of community and their future perspective,” Lawrence said, “so they’ll be able to think about, ‘I can fit into this culture; I can do these jobs; I can apply to this when I’m done.’”

Albanese said other efforts by the union across the state specifically target groups as diverse as formerly incarcerated people and political refugees from Burma. In Buffalo, he said, Local 210 and EDF Renewables set up a fund to pay incoming trainees for four weeks while they attended a boot camp of sorts before starting their actual apprenticeship.

“We hope that this could be a model with a lot of other developers,” he said. “This has been a really successful program.”

But there are other barriers that a stipend cannot bridge. Older workers near the top of pay scale have cars and are accustomed to long commutes, while young workers just starting out may not. The union does not have a solution for everything, Albanese said.

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SERC: Cybersecurity Means Going Beyond CIP Standards

Presenters at a webinar hosted by SERC Reliability on Wednesday warned utilities that ransomware is a much bigger threat than many of them realize, and major efforts are still needed to make operational technology and information technology assets safe from infection.

“It’s a global thing. It just affects every industry and anyone who is connected to the internet from an enterprise perspective,” Etinnie Burnett, a Critical Infrastructure Protection (CIP) auditor at SERC, said in his presentation on ransomware at the regional entity’s 2023 CIP Spring Security Webinar. “Whether it be OT [or] IT, this affects you in the way we look at how we reduce that risk. It’s an overarching thing; it’s not just a piece of a pie; it’s the whole pie.”

Burnett cited recently released data from cybersecurity firm Dragos that it tracked 605 ransomware attacks against industrial organizations worldwide in 2022, nearly double what it saw the year before. About 41% of those incidents affected organizations in North America. (See Dragos: Cyber Landscape Remained Volatile in 2022.)

Ransomware-incidents-map-(Dragos)-Alt-FI.jpgCybersecurity firm Dragos recently announced that North America accounted for more ransomware incidents than any other region in 2022. | Dragos

 

While just 29 of last year’s ransomware attacks targeted the energy sector, Burnett said utilities should take the threat seriously, because even a single successful intrusion can cause major disruptions. He pointed to the Colonial Pipeline breach of 2021, which caused the nearly weeklong shutdown of a major fuel supply network and led to a regional emergency declaration affecting 17 states and D.C., saying the case illustrates that companies can suffer even when an intrusion only directly impacts a company’s IT network, rather than the OT environment that directly manipulates its physical tools. (See Biden Directs Federal Cybersecurity Overhaul.)

Burnett also highlighted the Black Basta cyber gang, a suspected offshoot of the Conti and REvil groups that breached Chicago-based construction and engineering firm Sargent & Lundy last October. Sargent & Lundy has significant interaction with the bulk power system; the description of its work on its website mentions “electrical grid modernization, renewable energy, energy storage, nuclear power and fossil fuels.”

The firm’s notification of the breach, released in December, said the hackers are known to have accessed the names and Social Security numbers of “over 6,900 individuals.” Burnett said this exposure could easily put business connections of the firm at risk, showing how “it’s not always the entity; it’s who the entity does business with. How are [they] protecting my data as well?”

Burnett then pointed to a paper from 2016 surveying electric utilities on the effect of NERC’s CIP standards. While the standards are intended to address cyber and physical security risks, Burnett noted that many respondents held an ambivalent view on them, citing concerns such as the difficulty of NERC’s deliberative standards development process keeping pace with the rapidly changing cybersecurity landscape.

While Burnett acknowledged these fears, he said they should serve as a catalyst to utilities to build cybersecurity programs that go beyond the bare minimum requirements of the CIP standards. He urged utility leadership to recognize that “there’s no [one] standard that I can speak to that is going to solve this problem.”

“Every standard is a key part of reducing the ransomware [threat], and cybersecurity [must be viewed] as a threat in the larger context,” Burnett said. “So we cannot be single-minded — we can’t think, ‘We’re just in our little bubble, and this is my part of the process, and this is their part of the process. The silo mentality, when it comes to ransomware, is risky, because … we won’t catch [those risks] until after the fact.”

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NYPA Leader Says Expansion not Threat to Private Sector

The head of the New York Power Authority said Tuesday that the utility’s proposed renewable energy development role is a necessary part of the state’s drive to clean energy.

Gov. Kathy Hochul is seeking to expand the state-owned utility’s capabilities as part of her state budget plan.

But energy developers and their legislative allies have said the private sector is capable and willing to do the work needed to decarbonize New York’s power grid, and NYPA should not be placed in competition.

Justin Driscoll (New York Power Authority) FI.jpgJustin Driscoll, acting president of the New York Power Authority | New York Power Authority

Acting NYPA President Justin Driscoll told the State Senate Energy and Telecommunications Committee on Tuesday that it is not an either-or proposition.

“Given the challenge we’re facing here, we need all the tools in the toolbox,” he said. “Government can play a role. Nobody is suggesting that government be the only tool. But just given the enormity of what we’re looking to achieve here, we think that NYPA and government can play an ancillary role in the energy transition.”

Driscoll explained that NYPA could take on smaller projects that the private sector might skip; collaborate with the private sector on larger renewable development; or provide siting for these projects on land it owns.

“So I think it’s just additive to what the industry is doing now,” he said.

Large-scale renewable projects that have been awarded contracts by the New York State Energy Research and Development Authority would get New York to 66% statewide renewable generation. This is close to the 70% mandate set for 2030, but Driscoll noted not every project will be built. So, more is needed.

“Can NYPA be additive to that private-sector work? I think so,” he said.

Some critics say Hochul’s proposal to expand NYPA’s responsibilities goes too far by creating potential competition with the private sector. Other critics say Hochul’s plan doesn’t go far enough, as it only authorizes, not requires, NYPA to undertake development and does not fold in provisions to boost organized labor. (See Hochul Proposes Expanded Clean Energy Role for NYPA.)

Driscoll earlier this month told a Senate budget hearing that NYPA needs discretion to pick and choose projects because of its finite resources and said he thinks there are sufficient labor protections in Hochul’s plans. (See NY Legislators Press Hochul Officials on Energy Transition.)

Nor, he said Tuesday, would NYPA’s status as a public agency enable it to sidestep regulations, oversight and local accountability on any projects it did undertake.

Senators asked Driscoll about nuclear fission and hydrogen combustion. While neither emits carbon dioxide, some climate activists say they should not be classified as clean energy.

“I can tell you around the country there’s a lot of interest in the deployment of small modular reactors,” Driscoll said. “We won’t be a leader, I don’t think, certainly at the Power Authority. Other states will potentially lead the way, and we’ll see what comes out of that in the way of efficiency [and] safety. Obviously nuclear is a huge piece of where we sit today in terms of our clean energy.”

Hydrogen, he said, is certainly going to play a big role in the energy transition.

“The big question for industry is, what’s the right role for hydrogen?”

NYPA undertook a pioneering test of fuel mixtures of up to 40% hydrogen at its natural gas-fired peaker plant east of New York City, Driscoll noted. (See NYPA Reports Successful Hydrogen Test at Natural Gas Power Plant.)

“We have no plans to utilize hydrogen in any of our power plants, but we thought it was important learning.”

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NYDPS Gives Go-Ahead to CHPE Construction

The New York Department of Public Service on Monday authorized the Champlain Hudson Power Express (CHPE) to begin construction on the line, which will deliver Canadian hydropower to New York City (10-T-0139).

DPS approved the CHPE’s revised Environmental Management and Construction Plan (EM&CP) for Segments 1 and 2 after determining they complied with the state’s conditions, including facility design and maintenance plans, environmental and agricultural controls, and construction coordination.

Segment 1 covers the installation of conduit and cables spanning approximately 7.4 miles from the western shore of Lake Champlain in Putnam Station along County Route 3 and Lake Road to its intersection with State Route 22, while Segment 2 covers approximately 10.2 miles starting at the end of Segment 1 and following Route 22 until arriving at Bellamy Street, where it will connect to Segment 3.

The entire 339-mile CHPE high voltage direct current (HVDC) 1,250-MW transmission line will deliver hydropower from Montreal, Quebec, to Astoria, Queens. (See Champlain Hudson Power Express Closes on Financing.)

CHPE Construction Schedule (CHA Consulting) Content.jpgAnticipated CHPE segment construction schedule | CHA Consulting

Both the CHPE and the Clean Path New York are Tier 4 transmission projects, intended to increase the penetration of renewable energy into New York City, which relies heavily on fossil fuels.

NYISO’s 2022 Reliability Needs Assessment highlighted the importance of completing Tier 4 projects like the CHPE noting significant delays could mean emissions-producing peaker plants may need to remain operational longer than expected to ensure resource adequacy margins and grid reliability are maintained. The project is four months behind the November 2022 construction start date presented in the EM&CP. (See NYISO RNA Raises Concerns over Timing of Peaker Unit Retirements.)

The New York State Energy Research and Development Authority, which issued the solicitation that resulted in the CHPE’s selection, told RTO Insider the agency “is excited to see the Champlain Hudson Power Express (CHPE) start construction efforts in earnest, after the groundbreaking last fall and the creation of laydown yards along initial portions of the route.”

Transmission Developers Inc. (TDI), which is developing the CHPE, called it “a unique and incredibly complex construction project resulting in an equally complex review process.”

Jennifer Laird-White, TDI’s vice president of external affairs, told RTO Insider that as the CHPE “advances and both the state regulatory agencies and the world-class CHPE construction team adjust, the EM&CP pace will quicken.”

“The CHPE team is aware of our importance in the state’s nation-leading Climate Act goals, and we look forward to helping New York meet them,” Laird-White said via email.

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NJ Regulators Seek ‘Proactive’ Grid Upgrade Plans from Utilities

With a goal of modernizing New Jersey’s grid, the Board of Public Utilities (BPU) is close to concluding a new rules package that includes a requirement that utilities regularly identify barriers to interconnecting renewable energy resources.

The rules, which are in the final stages of public input before enactment, would require utilities to file a Proactive System Upgrade Plan (PSUP) every six months for needed “proactive circuit and system upgrades aimed at expanding opportunities for customer-generator facilities.” The plans would have to include the costs and benefits of the upgrades.

The package is part of the BPU’s effort to incorporate utilities in a regular planning cycle that would “eventually help drive a more nimble, flexible and responsive grid that accurately telegraphs intended capacity improvements and produces the highest societal benefits” for distributed energy resources, according to a BPU presentation at a meeting Feb. 10.

The proposal is under evaluation as the state and its utilities, like those in other states, are wrestling with the issue of how to connect the rapidly growing number of renewables to an aging grid that in some areas can’t handle any new interconnections; those it can take are often subject to lengthy delays.

The plan, and five other rules and process proposals outlined at the Feb. 10 hearing to solicit public input, were drawn from a report by consultancy Guidehouse on how to modernize the grid and improve interconnection rules. (See NJ Solar Sector Calls for Speedy Grid Modernization Plan.)

Paul Heitmann, program manager of the BPU’s Clean Energy Division, who moderated the hearing, said the board’s goal is to reduce barriers to the adoption of DERs. That means “improving access to relevant information for applicants, managing the queue and reducing processing intervals where we can,” he said.

To that end, the BPU’s rules include:

  • a series of new definitions for parts of the interconnection process that would make it clearer how the process would proceed;
  • improvements to the application process to give applicants greater access to key information needed in the process, to better manage the queue and make the process more transparent and accountable;
  • an increase in the threshold of a project that requires more intense study before connection, so that more projects are considered smaller and allowed to proceed with a simpler study;
  • revisions to “more clearly define the expected intervals and actions” needed by all stakeholders to move applications forward in a predictable and timely manner; and
  • a requirement that utilities complete an annual hosting capacity analysis, which would identify locations with spare capacity. The analysis would include the compilation of data at both the circuit and substation level, and a requirement that updates to hosting capacity maps be done every three months.

Flagging Weak Links

The PSUP is intended to create a system that will enable utilities to easily detect and report “if they are seeing where things are really congested and closed, and not available for hosting,” Heitmann said.

Those kind of problems might emerge as utilities conduct routine studies for individual products or “cluster studies” for several projects, he said. If the analysis produces data that says, “‘Boy, if we can upgrade this substation at a reasonable cost; this should be a fast-track opportunity,’” then the PSUP will convey that information to the BPU, he said.

“We don’t have that mechanism right now,” BPU General Counsel Abe Silverman said. “But this opens up the channel for that to come in play.”

In response to a question from stakeholder on how the information would be used, Heitmann said the reports will provide a proactive look at “which segments of the distribution system have deficiencies, relative to hosting capacity and ability to connect.”

“When that’s filed, that is a reference point that we now have as useful information to see where new applications are coming in,” Heitmann said. “Does it align to this intent already? Does it support the deficiency?”

In some cases, the new process would mean the BPU allows a developer looking for an interconnection to “come in and request that the utility build the upgrade identified in the PSUP, and then pay their pro rata share of those costs,” Silverman said.

“This is a little bit of a departure from sort of normal business as usual,” he acknowledged, adding that the board is keen to get stakeholder thoughts on how the process should work.

Ensuring Equity in Upgrades

One attendee, who was identified only as Steve, encouraged the BPU to make decisions with the involvement of a consumer advocate who is focused on community equity and can provide a perspective that looks beyond a system in which upgrades are selected by the utilities “based on physics and best value.”

“We all know when people need to interpret results and make judgments, equity often suffers,” he said. “So, I just want to make sure that we’re not targeting upgrades and areas that are already benefiting from a lot of DER penetration and [that we are] keeping in mind communities that might not have benefited from it as of yet.”

Heitmann agreed, saying that the utility filings would have to “address that fairness and balance, as well as the physics.” He added that the governor’s Office of Equity would be involved in the process to make sure that happens.

Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association, said the PSUPs will need to look beyond individual cases so that they can address issues from a broader view that includes taking into account the kind of problems that “can be anticipated to impact large sections of the grid.”

He cited the example of areas with a density of solar installations where it can be clearly expected that substations will need to be upgraded.

“It’s obvious that this is going to happen in areas where solar concentrates,” he said, explaining that “if it’s expected that many, many substations are going to need this,” the BPU should respond accordingly.

Silverman said that is precisely the kind of “fundamental” question that the BPU is looking to address, and he characterized it as asking, “How do we how do we advance distribution planning writ large?”

“I would think of this as an early attempt to identify those places, not necessarily as a replacement for a full integrated distribution planning proceeding,” which will have to take place later, he said. “Think of this as the first … baby toddler step towards accomplishing exactly what you’re saying.”

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MISO States Ramp Up ROFR Legislation

State legislatures in MISO’s footprint are undertaking a flurry of activity on right-of-first-refusal legislation as major transmission planning surges.

In Mississippi, ROFR legislation has cleared both houses of its legislature and is set to be signed by the governor later this month. Missouri and Kansas are currently mulling adding ROFRs for their utilities.

Eight MISO states already have ROFR laws, which give incumbent utilities first crack at transmission construction: Indiana, Iowa, Michigan, Minnesota, Montana, the Dakotas and Texas. Wisconsin lawmakers have considered one but haven’t passed it.

Montana had debated whether to revise its ROFR law to include lines constructed in a “federally recognized reliability organization” instead of a “midwest reliability organization,” as is currently worded. But on Wednesday, the state’s Senate Energy and Telecommunications Committee voted 11-1 to table the bill (SB 353).

Minnesota is looking into repealing its ROFR law. Had it not been for the legislation, MISO would have opened the $115 million, 50-mile, 345-kV Huntley-Wilmarth line to competitive bidding in 2016. Cost overruns related to a routing change pushed construction estimates beyond $150 million in 2020. (See Major MISO Tx Projects Face Various Hurdles.)

Indiana’s latest ROFR revision has cleared the House of Representatives and is before the Senate. The state currently maintains ROFRs for transmission projects within its utilities’ service territories. The new bill will extend that right to interregional projects as well, effectively overriding FERC Order 1000 (HB 1420).

An Indiana state representative recently said MISO has been involved in lawmakers’ proposal to re-establish a ROFR for interregional projects. During a Feb. 7 meeting of the Indiana House Utilities, Energy and Telecommunications Committee, Rep. Edmond Soliday (R) appeared to assert that MISO supported the legislation.

Soliday said he was “amazed” during a recent meeting with MISO executives how an unnamed vice president said, “We need this [ROFR] bill; we need this bill in Indiana.”

“So that’s why we brought it forward,” Soliday said during the hearing.

Soliday did not clarify his comments, nor identify who he was in conversation with after multiple requests from RTO Insider. MISO declined to identify the executive in question.

Through a spokesperson, the RTO reiterated that it is “not a policymaker and does not take positions on legislative matters.” However, Brandon Morris said, “MISO routinely has informational conversations with regulators and policymakers about the potential impacts of new rules or regulations.”

“We do not advocate for legislation, but we do outline the realities of complying with specific laws related to transmission planning and grid operations. We simply provide the facts so they can reach their own conclusions,” Morris said in an emailed statement to RTO Insider.

Indiana Rep. Matt Pierce (D) said his “no” vote on the bill’s advancement came down to his belief that having a “disinterested party like MISO manage the bid process would bring us more robust competition than we might see under this bill.”

The argument mirrors national trends in ROFR legislation. Critics say the laws restrict competition while supporters maintain that the projects are best left to the utilities that understand their systems best.

Ameren Missouri Vice President of Regulatory Affairs Warren Wood said recently in a company advocacy website that his utility supports the legislation because it “is crucial to ensuring Missouri electric utilities are the architects and builders of our state’s transmission projects moving forward.”

Last week, Oklahoma Senate Energy Chairman Lonnie Paxton announced he would not hear Oklahoma’s proposed ROFR legislation, calling it anticompetitive.

Industrial Energy Consumers of America President Paul Cicio said the bill’s failure is a win for consumers.

“Other states considering these anticompetitive and unconstitutional ‘right of first refusal’ bills such as Indiana, Mississippi, Kansas, Missouri and Montana should follow Oklahoma’s example and reject them,” he said in a statement. “With record investment into America’s electrical grid expected in the next few decades, it is vital that states find cost-effective ways to build transmission infrastructure while promoting innovation. Competition is the only way to achieve those goals. The interests of the consumer will win out.” At the time of Cicio’s statement, Montana’s ROFR bill was still being considered.

Cicio’s organization is part of a consumer alliance asking FERC to block MISO and other grid operators from applying “anticompetitive” ROFR laws to their regional transmission planning and cost-allocation processes (EL22-78). The complaint is pending at FERC. (See Consumer Groups File FERC Complaint Against MISO.)

The group said ROFR laws conflict with the commission’s rules on transmission competition and its obligation to establish just and reasonable transmission rates. It asked FERC to prohibit MISO from recognizing state ROFR laws in its $10.4 billion, 18-project, long-range transmission plan. Only about 10% of the portfolio is open to competitive solicitation.

The alliance also includes the Coalition of MISO Transmission Customers, the Wisconsin Industrial Energy Group, Resale Power Group of Iowa, Association of Businesses Advocating Tariff Equity and the Michigan Chemistry Council.

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Vistra Favors PCM’s Emphasis on Dispatchable Gen

Vistra (NYSE:VST) CEO Jim Burke took a wait-and-see approach Wednesday to ERCOT’s market redesign that is currently being debated by regulators, legislators and stakeholders, pointing out there are many details yet to be determined.

“I think there’s really a couple concepts we would want to make sure when we get through the stakeholder process,” he told financial analysts during Vistra’s year-end earnings call. “One is, is it material enough to attract investment? And is it enough to retain the generation that’s currently there?”

Attracting new generation and retaining new generation, primarily dispatchable, are the two goals behind the performance credit mechanism (PCM) that the Texas Public Utility Commission has offered up for vetting by the state’s legislature. The construct would reward generators — like Vistra’s Luminant subsidiary — in ERCOT’s energy-only market with credits based on their performance during a determined number of scarcity hours. (See Texas PUC’s Market Redesign Dominates ERCOT Market Summit.)

“I think it’s too early to say what the PCM is going to provide, obviously,” Burke said. “We believe in that dispatchable resource emphasis around PCM. We think that’s core to grid reliability. But there’s too many things to still work out in the stakeholder process.”

Vistra reported year-end adjusted EBITDA from ongoing operations of $3.12 billion, as compared to 2021’s performance of $2.03 billion. The February 2021 winter storm had a largely negative effect on the company’s earnings the year before.

For the quarter, ongoing operations adjusted EBITDA was $771 million, down from the year prior of $1.19 billion.

The company uses adjusted EBITDA as a performance measure because, it says, outside analysis of its business is improved by visibility into both net income prepared in accordance with GAAP and adjusted EBITDA.

While Vistra keeps a keen eye on the PCM and its possible benefit to thermal generation, it continues to transition its generation fleet to lower-carbon resources through investments in solar and battery energy storage developments. It added 418 MW of zero-carbon generation and storage in Texas and retired about 2.9 GW of fossil units in Ohio and Illinois.

The company plans to add 350 MW to its Moss Landing battery storage project in California. That will increase the facility’s capacity to 750 MW.

Vistra’s share price closed down 28 cents Wednesday at $21.71 after briefly reaching $22.41 following the earnings release.