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November 20, 2024

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MISO Updates Stakeholders on $10B Long-range Tx Package

MISO focused on its first long-range transmission portfolio (LRTP) package twice last week, revealing an early price tag during its March Board Week and then holding a stakeholder workshop Friday to address cost-related questions.

The RTO has cut one long-range project from its final lineup, dropping one of two 345-kV lines in southern Minnesota. That reduced the portfolio’s cost to $10.4 billion, down from a previously announced $13 billion, while staff continues to refine cost estimates. (See MISO Delays $13B Long-range Portfolio’s Recommendation.)

Even as MISO pushed back the board’s consideration of the portfolio to July, it said it wants to move quickly in strengthening the grid with new lines. Its planners have said the seven 345-kV projects should relieve congestion that the Independent Market Monitor regularly warns of and tracks. (See MISO Says System Volatility Here to Stay.)

The grid operator doesn’t yet have estimated in-service dates for the projects.

Jarred Miland, senior manager of transmission planning coordination, said the LRTP is the most expensive package MISO has put forward. He also said it represents the most extensive planning work the RTO has ever performed.

A final list of 345 kV projects (MISO) Alt FI.jpgA final list of 345 kV projects from the first cycle of MISO’s long-range transmission planning | MISO

 

The projects will ease growing pains as MISO grapples with increasing renewable energy output and the loss of large, centralized power plants, Miland said. He pointed out that the interconnection queue contains almost 56 GW of solar projects alone.

“The LRTP is not a one-and-done. It’s a journey,” Miland said of the first cycle of projects.

MISO will begin work on a second cycle sometime during the third quarter, Miland said. The second portfolio will focus on MISO Midwest, as did the first. MISO South won’t enter the planning picture until the third and fourth iterations of long-range planning.

“It’s a big system. It’s a tremendous amount of work,” Miland said. “We do recognize that there is a lot more work to do. That’s why we’re moving into tranche two. It’s a big apple. We can’t eat it all at once.”

The seven groupings of 345-kV projects include:

  • a $955 million line from Jamestown to Ellendale and Big Stone to Alexandria to Cassie’s Crossing in Western Minnesota and the Dakotas;
  • a $1.2 billion line that crosses Minnesota into Wisconsin, hitting Wilmarth, North Rochester, Tremval, Eau Claire and Jump River;
  • a $673 million line from Minnesota into Wisconsin that touches Tremval, Rocky Run and Columbia;
  • an $853 million line in Western Minnesota and the Dakotas that intersects Iron Range, Benton and Cassie’s Crossing;
  • an $894 million line in Iowa that passes over Webster, Franklin, Morgan Valley and then Beverly to Substation 92 near West Liberty;
  • a $2 billion line situated mostly in Northern Missouri that includes Orient, Iowa, and extends into Meredosia, Ill.; and
  • a sprawling, $3.4 billion line that links Iowa, Illinois, Indiana and Michigan.

The portfolio also provides for $350 million in lower voltage “under-build” projects necessary to accommodate the 345-kV transmission. MISO is still working to compile a list of the under-build projects.

“The under-build sort of represents … a high-end bogey as to where we’ll end up,” Miland said.

Miland said anytime MISO introduces new, large transmission projects, power system flows and contingencies could change and necessitate new equipment.

Indiana Utility Regulatory Commission staffer Dave Johnston asked whether the massive Iowa-to-Michigan project in the Central Region will be open to competitive bidding and whether it will be split up by jurisdiction into project segments.

MISO Executive Director of System Planning Aubrey Johnson said staff has yet to finalize those details.

“We have to think about some natural break points,” Johnson said, citing recent rights-of-first-refusal legislation in Michigan, Minnesota and Iowa. Wisconsin lawmakers are also considering ROFR laws.

MISO said its steady-state analysis of the Iowa-to-Michigan line show that it “can mitigate severe thermal issues in Michigan, Indiana, Illinois, Missouri and Iowa,” including reduced loading on 78 monitored facilities.

The grid operator is currently drafting an appendix to its 2021 Transmission Expansion Plan (MTEP 21) for the long-range projects. The portfolio will be part of MTEP 21, although its project approvals will take place about six months after the $3 billion MTEP 21 was approved.

MISO plans to divide costs of the long-range plan using a subregional, 100% postage stamp to load rate that is pending before FERC.

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FERC Rejects Waiver Request for QF Filing Requirements

FERC said Thursday that a new renewable energy investment firm cannot cut corners when applying for qualifying facility statuses.

Irradiant Partners, an Austin, Texas-based private equity firm focusing on clean energy infrastructure, asked the commission last November to waive a requirement that it submit recertifications for generators to be qualifying facilities (QF) under the Public Utility Regulatory Policies Act.

The commission, which requires a QF’s status be recertified when a generators’ upstream management changes, declined the ask (EL22-8).

Irradiant was spun off from Kayne Anderson Capital Advisors in October. Upon forming, it acquired a controlling ownership interest in a portfolio of 185 small renewable generation projects across the country. The equity firm argued that the facilities were all under 20 MW and not yet in operation. Irradiant also said Kayne Anderson, despite not being under FERC jurisdiction, had already filed for QF statuses.

FERC rejected the argument, saying it’s important it have current and accurate QF information on file. It said that a change in upstream control is too big to overlook.

“The commission has found that ownership information, in particular, is important; it assists the commission in monitoring potential discrimination in the provision of service and in reviewing the extent to which QFs should continue to be exempt from various provisions of the [Federal Power Act] and state laws,” it said.

The commission also rebuffed Irradiant’s argument that preparing and filing nearly 200 recertifications would be too labor-intensive and too time-consuming. It said because Kayne Anderson had already applied for QF statuses, Irradiant largely had copy-and-paste work ahead of it.

Irradiant “is overstating the time and effort” required to reapply for QF status, the commission said. It said for each facility, Irradiant must provide mostly “fill-in -the-blank or check-the-box” information on six or seven pages in addition to supplying one- to two- paragraph descriptions for the renewable generators.

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FERC Approves BPA’s 2022 Power and Transmission Rates

FERC last week approved the Bonneville Power Administration’s proposed 2022 wholesale power and transmission rates — a formality by the commission that carries little weight under federal law.

Under the Northwest Power Act, FERC’s review of BPA’s proposed rates is limited to determining whether the rates:

  • are sufficient to assure repayment of federal investment in the Federal Columbia River Power System over a “reasonable” number of years after meeting BPA’s costs;
  • are based on BPA’s total system costs; and
  • equitably distribute the costs of the federal transmission system between federal and non-federal generation.

Unlike its jurisdictional authority over public utilities under the Federal Power Act, FERC does not hold authority to modify BPA’s proposed rates, which are developed by BPA’s federally appointed administrator and then submitted to the commission for approval or disapproval.

“In this regard, the commission’s role can be viewed as an appellate one: to affirm or remand the rates submitted to it for review,” FERC noted in its order Thursday (EF21-3).

Under its rate proposals, BPA estimated that the filed rates will produce average annual power revenues of $2.774 billion and annual transmission and ancillary services revenues of $1.151 billion, sufficient to recover its costs for the 2021-23 rate approval period while also providing 95% probability that it can make all required payments to the U.S. Treasury Department on time.

“The traditional measure of the adequacy of Bonneville’s revenues has been the power repayment study,” the commission wrote. “Bonneville’s generation and transmission repayment studies indicate that the revenues expected to be collected under the proposed rates will be sufficient to recover the total system costs, including the recovery of the remaining federal investment, with interest, over the repayment period.”

The commission’s order also rejected a joint protest by the Idaho Conservation League, Great Old Broads for Wilderness and Idaho Rivers United, who argued that BPA has not met its statutory obligation to “protect, mitigate, and enhance fish and wildlife” affected by the federal hydropower system or demonstrate “equitable treatment” for fish and wildlife overall.

The protesters contended that the Northwest Power Act requires that BPA’s funding decisions be subject to an “equitable treatment” mandate and that the agency must take the Northwest Power and Conservation Council’s fish and wildlife program into account “to the fullest extent practicable” when setting funding levels for fish and wildlife mitigation. BPA’s failure to re-evaluate its fish and wildlife funding in the rate case represented a violation of the Northwest Power Act and Administrative Procedure Act, the protesters said.

In dismissing the protest, the commission agreed with BPA that the protesters’ arguments fell outside FERC’s limited jurisdiction over BPA’s rates under the Northwest Power Act.

“We agree with Bonneville that the commission’s review of Bonneville’s power and transmission rates is limited by Section 7(a)(2) of the Northwest Power Act,” the commission said. “Bonneville’s compliance with its environmental review and fish and wildlife protection obligations is thus outside the scope of the commission’s review under Section 7(a)(2). Because our review is limited to the relevant provisions of the Northwest Power Act, we do not address the joint protesters’ allegation that Bonneville has violated the Administrative Procedure Act.”

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DOJ Reveals Indictments Against Russian Energy Hackers

The U.S. Department of Justice revealed on Thursday that it has charged four Russian nationals for “attempting, supporting and conducting” computer hacking operations against the global energy sector, including electric utilities within the U.S.

In a media statement, DOJ officials said that the charges comprise two separate cases filed last year. The first set of charges was brought in June 2021 by a federal grand jury in D.C.

According to the indictment, Evgeny Viktorovich Gladkikh, a computer programmer working for Russia’s Central Scientific Research Institute of Chemistry and Mechanics (TsNIIKhM) allegedly worked with unnamed co-conspirators between May and September 2017 to hack into industrial control systems (ICS) and operational technology (OT) networks of an oil refinery outside the U.S. They later attempted a similar operation at a U.S. refinery but were unable to hack into the system at all.

The group installed malware on the foreign refinery’s network that was intended to disable the refinery’s safety systems, but when they deployed the malware, it instead caused “a fault that led the refinery’s … safety systems to initiate two automatic emergency shutdowns of the refinery’s operations.”

Gladkikh faces one count of conspiracy to cause damage to an energy facility, one count of attempt to cause damage to an energy facility and one count of conspiracy to commit computer fraud. The first two charges carry maximum sentences of 20 years in prison, while the last carries a penalty of up to five years.

Security Officers Targeted Power Plants

The other case involves Pavel Aleksandrovich Akulov, Mikhail Mikhailovich Gavrilov and Marat Valeryevich Tyukov, all officers in Russia’s Federal Security Service (FSB). A federal grand jury in Kansas brought the charges in August of last year, accusing the three men of a five-year operation targeting the supervisory control and data acquisition (SCADA) systems in U.S. energy facilities.

The plan had two stages: First, beginning in 2012, the defendants compromised the computer networks of ICS and SCADA system manufacturers and software providers and hid malware, dubbed “Havex” by cybersecurity researchers, in the update channels for their software products — a very similar plot to the 2020 hack of the SolarWinds Orion network management platform, also attributed to Russian hackers. (See FERC, E-ISAC Report Details Reach of SolarWinds Compromise.) According to the government, the group was able to install malware on more than 17,000 devices in the U.S. and overseas, including its targets in the energy sector.

In the second stage, the hackers shifted tactics to compromise specific energy sector entities, as well as individuals and engineers working with ICS and SCADA systems. This phase brought spearphishing attacks against more than 3,300 users in both the private and public sector. Successfully compromised targets included the Wolf Creek Generating Station, a nuclear plant in Kansas, although the release said the hackers only gained access to the plant’s business network, not the SCADA systems.

Akulov, Gavrilov and Tyukov face multiple counts, including conspiracy to cause damage to the property of an energy facility, conspiracy to commit wire fraud and aggravated identify theft. All of the charges carry maximum sentences of five to 20 years in prison, except for the identify theft charge, which carries a minimum sentence of two years in addition to any other sentences imposed.

Russia’s Continuing Cyber Threat

At the same time DOJ released news of the charges, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) issued a release providing more detail on the suspects’ hacking operations. The U.S. State Department also added the four men to its Rewards for Justice page, offering rewards of up to $10 million for “information leading to [their] identification or location.”

Concern over Russian hacking capabilities has been growing for years; DOJ previously charged six Russian military intelligence officers for cyberattacks against Ukraine’s power grid in 2015 and 2017, along with attacks on the 2018 Winter Olympics in South Korea and others. (See Six Russians Charged for Ukraine Cyberattacks.) Those fears have only grown more acute following Russia’s invasion of Ukraine last month, with experts warning that Russian President Vladimir Putin could lash out with electronic warfare as conventional military operations lose momentum. (See Experts Warn Cyberwar Still Possible.)

“Russian state-sponsored hackers pose a serious and persistent threat to critical infrastructure both in the United States and around the world,” said Deputy Attorney General Lisa Monaco. “Although the criminal charges unsealed today reflect past activity, they make crystal clear the urgent ongoing need for American businesses to harden their defenses and remain vigilant.”

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MISO Says System Volatility Here to Stay

MEMPHIS, Tenn. — MISO sees no end in sight to the system volatility that could plunge it into springtime emergency operations, staff said Thursday during a quarterly markets review.  

“We face a rapidly transforming energy landscape,” CEO John Bear told directors during a Board Week meeting, warning of a delicate load-supply balance.

He said when MISO introduced its ancillary services market 12 years ago, “load was the only thing that was moving around.”

“Everything else was pretty static and predictable,” Bear said. “Where we stand is not sustainable, and it’s not safe. We have a lot of work in front of us.”  

COO Clair Moeller said the RTO is laser focused on a “safe, reliable and affordable” transition despite proliferating operational complications.

“We’ve spent most of our time in committee meetings talking about volatility and uncertainty,” Moeller said, referring to the week’s activities.

“In the year 2000, volatility was a deterministic thing,” he said. “The volatility that’s facing us is more probabilistic than deterministic.”

Wayne Schug, MISO’s vice president of strategy and business development, said a growing renewables fleet and rapidly changing weather is driving increasing volatility and an “inability to deal with it.”  

By 2030, as little as 57% of the RTO’s fleet could be dispatchable, staff said. Dispatchable resources accounted for 84% of the fleet in 2020.

Schug said that since 2017, average daily output swings and forecasting errors have grown by gigawatts and percentages points, respectively. He said while the grid operator continues to get better at output forecasting, the expanding wind fleet has blotted out any signs of improvement.

“I caution you about averages,” Schug said. “Our extremes are much higher.”

Growing hourly wind Output (MISO) Content.jpg

Growing hourly wind output and volatility from 2008 to 2021

| MISO

 

Moeller said that for three days in 2020, MISO’s entire wind fleet in the upper Midwest failed to generate a megawatt. He also said unexpected cloud cover could make a solar farm “disappear within three minutes.”

MISO will work to pre-position its system for bad days, Moeller said. Executives said plans for seasonal capacity auctions and big-ticket transmission projects should help.

Director Mark Johnson asked staff to invite a control room operator to a board meeting to address their recent experiences dealing with grid volatility.

Staff Warns of Emergency Ops

MISO’s Zak Joundi said while the RTO should have adequate resources through spring, it could declare an emergency if faced with restricted generation output and high demand in April or May. He said the spring outlook echoes last year’s spring peak estimate and resource availability.

“Uncertainty can be especially exacerbated in spring,” he told the board’s Markets Committee Tuesday.

Joundi said MISO is working with an aging generation fleet more prone to outages with increasingly uncertain return-to-service dates. He said the footprint’s current rate of generation retirement — propelled, in part, by state and federal policies — is outpacing members’ capacity replacements.

Staff expects the number of emergency near-misses to rise every year, Joundi said. He said MISO may expand a weekly winter fuel security survey of fossil-fuel owners into a year-round task. (See MISO Winter Fuel Security Surveys Now Permanent.)

During the recent winter, MISO said renewable generation accounted for an increasing share of load. On Jan. 18, 24 GW of wind generation served 30% of the RTO’s load at one point. On Feb. 19, MISO reported its first seasonal solar generation peak of 1.6 GW.

“As the portfolio has transitioned to increased levels of wind output, operators are managing greater levels of volatility and uncertainty, making complex unit commitment decisions,” Joundi said. “How can we have the right market product to incentivize … the right kind of flexibility to complement this volatility?”

“There’s no magic bullet, market products and tools, or transmission,” Director Barbara Krumsiek said.

Joundi said that the control room now manages more intra-hour instability and intensifying “wind droughts,” where wind output drops off below forecasts.

“We’re seeing a lot more output and volatility on the wind side,” agreed MISO Independent Market Monitor David Patton.

Patton said MISO racked up about $750 million in real-time congestion costs during the winter, the most ever for a three-month period.

He said the grid operator is limited on wind generation it can export from the Midwest westward to SPP, saturating the system at times and lowering energy prices. Patton also said part of the congestion problem lies in SPP not modeling MISO’s constraints in its day-ahead market, making some uneconomic generation units appear economic in the SPP market. He said he was working with SPP and its monitor to fix the problem.

Patton also said drought conditions in the Canadian province of Manitoba led Manitoba Hydro to import more power from MISO, increasing constraints in the footprint’s northern portion. Manitoba Hydro’s Audrey Penner said a “deluge” of snow this winter will improve the situation as it thaws.

Coal generation’s share of energy output dropped from 41% last winter to 36% this winter, Patton said, because of retirements and limited coal supplies. Natural gas generation’s output share rose from 26% in 2021 to 29%. He said natural gas generation would have grown more this winter but for the “run up in gas prices.”  

Patton said he expects difficulties with securing coal to continue into the foreseeable future.

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DOE Calls for Better Engagement on Defense Infrastructure

In a report released this week, the Department of Energy found “significant opportunities” for improvement in its handling of the security needs of U.S. defense facilities and the utilities that serve them.

The report, titled “Strengthening the Resilience of Defense Critical Electric Infrastructure,” was produced by DOE’s Electricity Advisory Committee (EAC). It focuses on defense critical electric infrastructure (DCEI), defined in the Federal Power Act as “any electric infrastructure that serves” critical defense facilities (CDFs), themselves defined as critical to the defense of the U.S. and vulnerable to disruption of electric energy provided by an external service. It was based on interviews conducted with utilities that own and operate DCEI, which DOE dubs “responsible utilities” (RUs).

DOE launched its first program of outreach to RUs in 2019 under its Office of Electricity; the initiative was later shifted to the Office of Cybersecurity, Energy Security and Emergency Response (CESER). While the report’s intent was “not to criticize the DCEI program or its initial rollout,” the EAC found several areas where the implementation could be improved.

The first area has to do with the goals of the program — or rather the lack thereof. Many RUs complained about “DOE’s objectives for the DCEI program,” with one interviewee asking, “What are [the Department of Defense] and DOE trying to achieve here? That needs to be clearly articulated so industry can provide recommendations on how best to achieve” the program’s goals.

Others said they “don’t really know what DCEI is,” or complained that while the Fixing America’s Surface Transportation (FAST) Act of 2015 required DOE to identify CDFs and DCEI, it said “nothing beyond that.” This lack of clarity is compounded by the absence of a dedicated team within DOE to engage with industry, coordinate engagement between RUs and multiple DOE offices, and establish greater unity of effort between DOE and DOD. RUs reported feeling “whipsawed” with requests for engagement from both departments.

Questions on Funding and Resilience Targets

Another issue for many RUs is funding, specifically the question of how to pay for resilience improvements requested as part of the DCEI outreach.

This is a complex topic because a project intended to benefit a particular CDF may also benefit ordinary ratepayers in the region, leading some to suggest utilities should recover the cost for such projects through normal means. However, this is not guaranteed: A substation built in a remote location may benefit few or no ratepayers, while one in a crowded urban area may be expensive and have difficultly getting a permit.

In either case, such a project would not be the choice of the utility or the local customers, and requiring ratepayers to foot the bill would arguably be unjust. One RU observed that “the Pentagon never imagines that it could get F-35s for free” and criticized DOE for wanting “additional substations for free,” while another said that DOE and DOD should “find a pot of money to pay for” upgrades necessary for national security.

The challenge of identifying “specific resilience needs for DCEI” is “closely related” to that of funding, the report said, as it plays into the question of which projects to prioritize. The report called for resilience assessment tools, standards and metrics tailored to DCEI and the needs of utilities serving CDFs.

“What criteria should be established to assess progress toward achieving DCEI resilience goals? And are these goals appropriate to apply to DCEI and RUs, versus or in combination with applying them to CDFs for ‘inside the fenceline’ resilience?” the EAC asked. “These and other questions will take years to resolve and will need close coordination with initiatives on supply chain risk management, industrial control systems (ICS) security and other DOE resilience initiatives.”

Better Communication for Fast Response

RUs also suggested that DOE’s practices for sharing threat information with industry could be improved in light of the “harsh reality” that utilities serving defense facilities are likely to be targets in any coordinated action against the U.S. The report’s drafters noted a 2019 study that found “existing information sharing and partnership structures … neither agile enough nor tactical enough to respond to a cyberattack with the necessary speed.”

While the EAC acknowledged that progress has been made since then, it pointed to significant intelligence gaps that still prevent fast, flexible responses to new threats. Among the suggested solutions were:

      • a Critical Infrastructure Command Center: a secure space where senior executives and cybersecurity staff from different sectors can work with government to fight back against cyber threats; and
      • a Joint Collaborative Environment: a clearinghouse for sharing cyber threat data “among federal entities and between the U.S. government and the private sector.”

Finally, the report said its proposed DCEI team within DOE should lead more conversations on long-term policy changes. It is very possible that both the definition of CDFs and the understanding of their energy needs could change in the future, the report said; if they do, RUs will need to be informed promptly so that they can adapt their practices.

“Key to the success of improving DCEI resilience is establishing a structured, formalized team within DOE for industry engagement on DCEI issues,” the report said. “This would build upon the accomplishments made by DOE to date and serve as a prerequisite for moving forward on all the other proposals identified in this study.”

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FERC Extends Deadline to Justify Exceeding Price Cap in West

Sellers of spot electricity that exceeds the price cap for the Western Interconnection will have more time to justify the higher prices to FERC the commission ruled Thursday (EL10-56).

FERC approved a motion by Macquarie Energy and Mercuria Energy America to extend the deadline for cost-justification filings to 30 days after the end of the month in which an “excess sale” occurred.

Sellers currently have seven days to make the submission.

The commission established a price cap in the WECC area outside CAISO in July 2002 after the Western energy crisis of 2000/01, when widespread manipulation in the California market sent the wider region’s wholesale prices skyrocketing. The $250/MWh price cap set in 2002 was, with FERC approval, increased to $1,000/MWh in 2010 after CAISO raised its cap to that level.

When it set the price cap in 2002, FERC clarified that it was in fact a soft cap, saying that “prices can be above the cap but will be subject to justification and refund.” It also established the seven-day cost justification deadline.

In their identical requests to extend the filing deadline, Macquarie and Mercuria said the complexity of gathering information to submit a justification warranted more time.

After making an excess sale, the companies said they must identify the scope of trades above the soft cap and ensure the trades have been finalized from a contractual perspective. Then they need to “gather information about the market fundamentals and other factors driving prices,” as well as data related to production costs, opportunity costs and other indices supporting their arguments.

The sellers then have to identify other costs and risks and prepare the submission, including pleadings and declarations.

“Both parties argue that it is very challenging to complete these tasks in seven days, and they contend that 30 days from the end of the month of a trade is a more reasonable deadline,” FERC noted in its order.

The two parties also contended that changing the deadline would lessen the burden on FERC by reducing the instances when the commission must deal with repeated motions for extension and answers to those motions, as well as avoiding the need for sellers to make an initial filing to meet the seven-day deadline, followed by supplements to reflect changes.

Tenaska, Tri-State Generation and Transmission, Brookfield Renewable Energy and Trading and EDF Trading all filed comments in support of the plan. Tenaska said it appreciated FERC’s willingness to allow “one-off” extensions to the deadlines but said it was still challenging to assemble the needed data within seven days.

Tri-State said the commission’s recent approvals of extensions demonstrated the need for longer deadlines.

“We agree that allowing parties more time to gather the required information for a filing will likely lead to more complete filings, increase the likelihood that market participants will receive settlement data for relevant transactions that are billed on a monthly cycle, and will help ensure that market participants are considering all sales in a given month and are not making rolling submissions for each trade date,” FERC said in approving the motion.

“Finally, we expect that an extension will not only minimize the need for supplemental filings and amendments, but also reduce the number of requests for individual extensions,” it said.

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FERC Backtracks on Gas Policy Updates

FERC on Thursday walked back updates it made last month to how it would consider natural gas infrastructure applications, labeling the two documents as “drafts” and soliciting public comment.

The Democratic majority on the commission said they were concerned that the updates had created confusion and uncertainty, which the two Republican commissioners had predicted last month when they opposed the orders.

The commission had voted 3-2 to update its 1999 policy statement on natural gas infrastructure certificates (PL18-1) and released guidance on how it will evaluate the impacts of projects’ greenhouse gas emissions in its environmental analyses (PL21-3). (See Split FERC Updates Policies on Gas Infrastructure Applications.)

Combined, the two documents marked a significant change to how FERC would evaluate the need for gas projects and their impact on the environment, particularly the effect of their emissions on global climate change. But on Thursday, the Democrats said that after having conversations with and hearing feedback from developers, they reluctantly decided to delay the orders’ implementation.

“What I’ve generally heard is that the policy statements raise additional questions that could benefit from further clarification,” Chair Richard Glick said. “So we are re-engaging and inviting all stakeholders to comment on top of the 38,000 comments we’ve already received in response to two Notices of Inquiry.”

Glick was referring to the NOI issued under Chair Kevin McIntyre in late 2017 to revise the 1999 statement and the reissued notice in February 2021 that restarted the process after it had languished.

“This vote was a difficult one for me,” Commissioner Allison Clements said, “because I believe these policy statements were an important step forward in clarifying factors to be considered in making our public interest determinations and doing so consistent with court mandates. … Nonetheless, based on the engagement since last month’s meeting, I have concluded that we cannot move forward to effectively or efficiently consider and process individual project applications under the new policies without broader agreement across the commission.”

Based on statements from each of the Democratic commissioners, it was not clear what exactly gave them pause, and the orders had not been published as of press time. But Glick did say that after their finalization, they would only apply prospectively; they would not apply to any applications pending before the commission at that time.

While Republican Commissioners James Danly and Mark Christie had completely disagreed with the orders themselves, they were particularly incensed that they would apply to already filed applications without giving developers any chance to respond.

They also criticized FERC’s acting without public comment first, especially in the case of the GHG guidance, which the commission deemed “interim” while it gathered public comment by April 4.

Comments on the draft statements are due by April 25, with reply comments due May 25.

The move, along with three natural gas projects approved the same day (see below), were “case studies in why it is that every stakeholder should participate in the dockets in which they have an interest,” Danly said. “It was because in large measure of the participation of the affected parties that we find ourselves in the position we do. Never doubt the importance of the comments you file or the submissions you put into our dockets. They matter. They count. We read them.”

Consensus Possible?

Speaking to reporters, Glick said some developers were “interpreting [the two policies] in certain ways that I’m not entirely sure was intended. … Overall, we heard from them that there was a lot of confusion out there and … the goal here is to create less confusion and a framework for a legally durable approach.”

Asked whether he was concerned that the commission could reach any consensus on the policies, Glick said, “I still remain positive … that we can get to ‘yes’ in many [aspects]. I think we have to hear more and get a better record, which we’re going to do.”

But Glick made clear during the meeting and with reporters that the commission had to move forward with the changes. He noted that earlier this month, the D.C. Circuit Court of Appeals remanded another gas project approval back to the commission because of its failure to properly examine its greenhouse gas emissions. (See Court Again Rebukes FERC for Failure to Review Downstream Emissions.)

Willie Phillips 2022-03-24 (RTO Insider LLC) FI.jpgFERC Commissioner Willie Phillips | ©RTO Insider LLC

Glick was also asked if the move resulted from political pressure from Congress or the White House. Earlier this month the majority was strongly criticized by members of the Senate Energy and Natural Resources Committee, including its chair, Sen. Joe Manchin (D-W.Va.). (See Glick: No Regrets over Gas Policy Statements.)

“One hundred percent no, and I appreciate the question. I know you have to ask that question. I think … anyone who knows me knows that I’m not going to do anything for political purposes. FERC is an independent agency, and I very much honor that,” he said. He added that he believes the same of each of his colleagues.

The move also had nothing to do with the end of his term coming this June, he said.

“I actually like this job. If the president and the Senate are willing to let me stay, I will do so,” he said. “There’s things in life you can control, and there are things you can’t control. And I’m going to focus on the work and what we can control” at the commission.

After FERC’s open meeting, in what he said was his first speech since joining the commission, Commissioner Willie Phillips commented on the order at the American Council on Renewable Energy (ACORE) Policy Forum.

“You may have noticed that my colleagues and I had a couple of differences about a couple policy statements regarding natural gas recently that got a little bit of attention,” he said. “Today, we set those statements for additional comment to give us time to try to reach a more bipartisan solution. My colleagues and I take our independence as regulators very seriously. Some may even accuse us of digging into our positions and failing to compromise at times. I say: Let’s stop digging. That’s not FERC. That’s not me.”

3 Projects Approved

While FERC gathers public input, the commission will continue to consider gas project applications under the 1999 policy statement, Glick said.

On Thursday, the commission unanimously approved three such applications — though each commissioner issued a separate concurring statement for each of the projects. (These orders and statements were also not available as of press time.)

Glick said the commission found that the developers had demonstrated need for each project. He also noted that, based on his own projections, the projects’ emissions would not have a significant impact on climate change, though this was not a factor in the commission’s decisions. In fact, he said, one of the projects — Iroquois Gas Transmission System’s ExC Project in New York (CP20-48) — will actually reduce emissions because the transported gas will replace oil used for heating.

The other two projects approved were Kinder Morgan’s Evangeline Pass Expansion Project in Louisiana and Mississippi (CP20-50), and TC Energy’s East Lateral XPress project, also in Louisiana (CP20-527).

Rich Heidorn Jr. contributed to this report.

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Generators Vent Frustration with PJM, FERC to Ohio Senators

Glen Thomas (The Ohio Channel) Content.jpgGlen Thomas, P3 | The Ohio Channel

PJM stakeholders in the RTO’s generator sector Tuesday voiced frustration with FERC over recent decisions related to the capacity market, especially multiple delays to the Base Residual Auction (BRA), to a receptive audience in the Ohio Senate Energy and Public Utilities Committee.

The testimony from Glen Thomas, president of the PJM Power Providers Group (P3), prompted one senator to question whether the legislature could explore leaving the RTO.

Thomas told the committee that capacity resources in Ohio have done “very, very well” in the capacity market. Ohio has seen more than a dozen new power plants constructed in the last 15 years, leading to billions of dollars in investments and thousands of jobs, he said.

PJM’s capacity reserve margin numbers are currently “very strong,” Thomas said, creating short-term confidence in the market. But in the long term, P3 is “growing increasingly concerned” that reliability is going to become more of an issue in the future in PJM.

Steve Wilson (The Ohio Channel) Content.jpgSen. Steve Wilson | The Ohio Channel

“There’s a lot of things that have been occurring at the federal level that have a direct impact on Ohio’s energy policy, and there’s quite frankly some reasons to be concerned,” Thomas said.

Sen. Steve Wilson (R) said he was “scared to death” thinking about the long-term reliability issues Thomas talked about.

Wilson asked Lori Sternisha, director of the Office of the Federal Energy Advocate for the Public Utilities Commission of Ohio, what the legislature could do if FERC ends up forcing Ohio to pay for projects like offshore wind in New Jersey.

“Would we look to drop out of PJM, or what is our fallback plan if all of a sudden our reliability gets unacceptable and our price gets unacceptable?” Wilson asked.

Lori Sternisha (The Ohio Channel) Content.jpgLori Sternisha, PUCO | The Ohio Channel

Sternisha said her office is concerned with long-term reliability issues based on recent FERC decisions, but that PJM is responsible for making sure there are reliable resources throughout the RTO, and it continually conducts reliability studies. She said if new generation isn’t located close to load centers, new transmission may be a solution.

“It would be my hope going forward that we not run away from PJM but use our oversized voice to direct the policy and do the best we can in that regard,” Sen. Mark Romanchuk (R) said.

Regulatory Uncertainty

Panelists at the hearing spoke about the impact of PJM’s minimum offer price rule (MOPR) on Ohio’s energy sector.

PJM’s narrowed MOPR took effect in September after FERC deadlocked 2-2 on the RTO’s proposal to apply it only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction. The proposal became effective by operation of law under Section 205 of the Federal Power Act when the commission failed to act within 60 days. (See FERC Deadlock Allows Revised PJM MOPR.)

Thomas said PJM had used the MOPR to “keep competition fair and the playing field level” among states and to take subsidies out of the marketplace. But he said many states in the RTO are using subsidies to incent renewable generation, and without the MOPR, subsidized resources “enjoy a leg up” in the marketplace and Ohio resources are on an “uneven playing field.”

“We believe the market should dictate winners and losers,” Thomas said. “We believe that competition that drives down costs is a good thing.”

Thomas said P3 has also grown concerned about the pace of plant closures resulting from delays in the running of PJM’s capacity auctions. He said delays in the Base Residual Auction have led to closures for plants that may have been viable in an auction run on time.

The BRA for delivery year 2023/24 has been delayed three times — from May 2020 to December 2021, then to late January, and finally to mid-June — each from separate FERC orders on different aspects of the capacity market. (See FERC Approves PJM Capacity Auction Date Changes.)

Arn Quinn (The Ohio Channel) Content.jpgArnie Quinn, Vistra | The Ohio Channel

Arnie Quinn, chief economist for Vistra (NYSE:VST), cited the retirement of Vistra’s 1,320-MW coal-fired William H. Zimmer Power Plant, announced last summer.

The plant was originally scheduled to retire by 2027, but the deactivation was moved up to May 31. Quinn said the change was made after the results of the 2022/23 BRA last May — also delayed multiple times from its original May 2019 date — when auction prices cleared lower than Vistra expected, making the plant unprofitable. (See Capacity Prices Drop Sharply in PJM Auction.)

Quinn said Vistra debated keeping Zimmer in operation to see if capacity prices “rebounded” in the 2023/24 BRA. But he said FERC’s decision on PJM’s market seller offer cap (MSOC) and more delays in the auction made it “clear” that the commission was going to make it more difficult “to use our commercial and engineering judgment to reflect our costs” when the offers were presented to the capacity market.

“We should have had the opportunity to go to the market with a bid that reflected our view on how much it would take to keep that plant open,” Quinn said. “We didn’t give the market that option because we sensed a risk that those rules were going to disadvantage us.”

Sternisha said her office has voiced concerns before FERC on fair and competitive wholesale markets, ensuring Ohio ratepayers are not burdened by public policy initiatives of other states and advocating for control of increasing transmission costs.

FERC’s inaction on the MOPR and the repeated auction delays over the objections of PUCO are “concerning,” she said, and a wholesale capacity market without “appropriate guardrails” doesn’t provide reasonable price signals or compensation to all generating resources. The MOPR has been changed so many times that it was “watered down to the point that it provides little screen for subsidized, uneconomic resources entering the PJM capacity market.”

Senators’ Questions

Mark Romanchuk (The Ohio Channel) Content.jpgSen. Mark Romanchuk | The Ohio Channel

Sen. Romanchuk asked about Ohio and Pennsylvania’s combined energy consumption in PJM. 

Sternisha said Pennsylvania represents 19.7% of load in PJM, while Ohio is at 19.3%. 

Romanchuk said that should give the two states an “oversized voice” in PJM and federal policy decisions. Sternisha responded by saying she believes they “carry a lot of weight” in PJM and at FERC.

Sen. Teresa Fedor (D) asked if PJM’s capacity market has protections against generation resources that are “trying to game the system” through offering artificially low prices in auctions.

Quinn said the MOPR “is and was” the mechanism PJM has to deal with prices, and the new rule means “essentially no resource now has any limitations on how low they can get.”

Fedor asked Quinn what types of resources in PJM are “trying to game the system.”

Quinn said he wouldn’t characterize resources’ bidding behavior that way. “They have another revenue source that offsets the other costs that the wholesale market needs to pay for,” he said, referring to state subsidies. “That resource is reflecting that in their offer. I wouldn’t say the resource is gaming anything. The resource is expressing what their economic interests are. The state has changed the playing field for all resources.”

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Highlights from FCA 16: No New Gas, No Big Storage

New England’s Forward Capacity Auction last month offered no big surprises, but it did hint at coming shifts in the dynamics of the region’s energy supply.

While the FCA 16 clearing price fell in the Southeast New England zone, the market overall stayed relatively steady from the previous year’s auction, with minimal turnover in the generator fleet and relatively low prices. (See ISO-NE Announces Capacity Auction Results After Killingly Delay.)

It was, as one observer put it, the “calm before the storm” as New England prepares to transition away from the minimum offer price rule.

The new generation that entered this year came from storage and solar, with no new gas-powered generators or repowering projects.

“I think that reflects the fact that the economics are challenging for non-renewable resources,” said Scott Niemann, a director at the research and consulting firm ESAI Power. “And what’s coming in is really driven by public policy.”

ISO-NE published the full results of the auction in a FERC filing earlier this week.

Merrimack Station

New England’s last remaining coal plant, Merrimack Station in New Hampshire, cleared the auction.

But it did so after a dynamic delist bid that ultimately lowered its payments by 128 MW worth of capacity, or roughly $300,000 a month at the clearing price of $2.48/kW-month.

“That’s one of the units that’s clearly very much on the bubble in terms of being economic in the market, and that shows up in that some of those megawatts were not cleared,” Niemann said.

Storage

Standalone storage projects were “mostly locked out,” noted Aaron Geschiere, a senior analyst for Nexamp.

That likely stemmed from the end of the seven-year price lock rule, which allowed new resources to maintain their clearing price for seven years but was used for the last time in FCA 15 after FERC ordered its removal.

“There was more urgency to clear in the last auction so that the price could be locked in for seven years to facilitate financing and more certainty in returns,” Niemann said. “All of the projects that cleared in this auction were small batteries, compared to last auction where you had 100 or 200 MW individual projects clearing.”