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November 9, 2024

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Stakeholder Soapbox: Technology, not Subsidies, is the Key to Electrification

Ken Costello (Ken Costello) Content.jpgKenneth W. Costello

By Kenneth W. Costello

With deepening concerns over climate change, politicians, policymakers, electric utilities and environmentalists are advocating the idea of electrification: the replacement of fossil fuels with electricity for direct end uses like transportation and water and space heating. But most of these champions of electrification fail to consider its downsides.

Proponents want electrification to occur sooner than later, to be accelerated by subsidies and other governmental inducements. Some even advocate for mandated electrification and natural gas bans to avoid alleged climate catastrophe. Others point to the less lofty goal of revitalizing the electric industry, although electrification could cripple the natural gas and oil industries with significant job losses. Another group argues that electrification is already economical for end uses, like water and space heating. If that is true, why then do we need subsidies to induce energy consumers to switch to electric vehicles and heat pumps?

Many of the arguments supporting aggressive climate actions portray those actions as a free lunch. How could any reasonable person oppose them? Aren’t we facing a climate apocalypse that demands a full-court effort, regardless of the cost, to prevent it from happening? Anyone opposing electrification must be climate deniers or just plain wrongheaded. Proponents’ problem is that they view electrification at the 40,000-foot level, along with the false narrative that electrification can have more than a nominal effect on climate change.

Well, as with most things, there are two sides, and electrification is no exception.

Instead of artificially bolstering electrification with subsidies and mandates, which proponents of electrification would have us do, we should wait to see where electric technology takes us. Technology will determine the ultimate success of electrification — not subsidies and other governmental actions that are largely politically driven.

For electric vehicles, the challenges are still daunting: infrastructure investments — chargers, customer and utility upgrades in their distribution systems, rapid direct-current charging, education and outreach, range anxiety — limited battery storage capability, the availability of charging stations across the country and demands on the electric grid.

For heating, economics seems to be the toughest hurdle, as most electric heat pumps are only cost-effective in areas that have low electricity prices and moderate winters, at least in comparison to natural gas. Further technological improvements will make heat pumps more economically viable and markets — not government handouts — can best achieve that.

Whether energy consumers rely on fossil fuels or electricity for their transportation or space-heating needs comes down to a rational choice of what source of energy would best satisfy those needs. With few exceptions, consumers express their choices and make the best decisions for themselves.

We can say with confidence that accelerating electrification with government subsidies and mandates is a win-win for electric utilities and environmentalists but a loser for society as a whole.

The problem of new electric technologies subsidized by utility customers and taxpayers with only a distinct minority benefiting is hard to ignore, both politically and economically. It would likely have a regressive effect by disproportionately benefiting higher-income households while being funded by all income groups.

Before moving ahead with any action, policymakers should ask themselves what benefits electrification offers relative to the costs. It is unlikely that any justification would realize net benefits if the intent of accelerated electrification is solely to mitigate greenhouse gas emissions. It is somewhat puzzling, for example, why a state on its own, without cooperation from other states or the federal government or other countries, would overhaul its energy sector (which massive electrification would do) at a high transition cost for something that would largely benefit the rest of the world, namely, the mitigation of climate change.

Policymakers need to do their homework before extolling the wonders of electrification. They should especially place more trust in markets in assuring that when electrification occurs, it will be for the good of society — not just for special interests.

Kenneth W. Costello is a regulatory economist and independent consultant.

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FERC Accepts SPP’s Unexecuted FSA with Ponderosa

FERC this month accepted an unexecuted facilities service agreement (FSA) between SPP, Southwestern Public Service (SPS) and Ponderosa Wind II, finding it to be “just and reasonable and not unduly discriminatory or preferential” (ER23-672).

The FSA replaces an unexecuted generator interconnection agreement (GIA) filed by SPP in July and amended in September. In accepting the substitute agreement May 5, the commission said it conformed to the SPP tariff’s pro forma GIA.

The original agreement included a 20-year default term and allowed SPS to recover the return on and of the capital investment through a network upgrade charge that continued for the FSA’s term. Ponderosa protested the 20-year term, arguing that the FSA would double the overall amount paid for upgrades under the GIA. Instead, the developers proposed a three-year term to pay the money back faster.

The commission found the 20-year term to be just and reasonable because it will allow SPS to recover upgrade costs over a time period based on the utility providing interconnection service to Ponderosa. It said it was reasonable to expect interconnection service under the GIA to match or exceed 20 years.

Ponderosa II will add an additional 100 MW of capacity to the existing 200-MW facility in the Oklahoma Panhandle. The wind farms are subsidiaries of NextEra Energy Resources.

Evergy Compliance Filing OK’d

FERC also this month accepted Evergy Kansas Central’s compliance filing after protests from several transmission customers challenged the utility’s implementation of its transmission formula rate (ER22-1205).

The commission on May 5 found that Evergy had complied with its directives in a December order by correcting its formula rates’ application in its 2022 annual update. It said the filing details how the revised formula rate billings’ calculations reduced its annual revenue requirement by more than $15 million.

Evergy also said it will provide refunds with interest in the next rate year’s annual projection.

FERC denied the utility’s rehearing request but granted its clarification petition.

Kansas Electric Power Cooperative, Kansas Municipal Energy Agency and Kansas Power Pool challenged Evergy’s initial filing last year, arguing that it incorrectly applied its formula rate according to its own instructions. They also contended that Evergy double-counted its undistributed subsidiary earnings in the formula’s equity capitalization component.

The transmission customers requested that FERC direct Evergy to correct the formula rate’s implementation and refund excess amounts collected in previous years. The commission in December granted in part and denied in part the formal challenge.

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MISO Rebrands System Restoration Working Group

MISO’s stakeholder committee chairs last week resuscitated a stakeholder group dedicated to emergency preparedness and system restoration training.

Steering Committee members voted at a May 10 teleconference to morph the System Restoration and Reliability Training Working Group into an Operators Training User Group (OTUG).

MISO said the sunsetted working group was effectively functioning as a user group because it did not make policy recommendations to the Reliability Subcommittee. It said policy decisions on power restoration processes have largely been handled through the subcommittee and the nonpublic Reliable Operations Working Group.

The OTUG will still serve as an outlet for discussions on operator training, system resilience, emergency preparedness exercises and restoration drills. When appropriate, the group will advise MISO and stakeholders on mitigating reliability risks through improved training.

User groups are not defined in MISO’s Stakeholder Governance Guide and therefore aren’t bound by the usual committee guidelines. User groups do not have to elect leadership. The grid operator said the new group will allow it to exert the same influence while having greater flexibility.

The OTUG will continue to report to the Reliability Subcommittee. Members will present a new mission statement, meeting dates and management plan to the subcommittee during its May 23 meeting.

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FERC’s Evolving Enforcement Practices Examined at EBA Meeting

WASHINGTON —  FERC’s enforcement powers have been impacted by some recent court cases, and the commission itself has some new priorities, experts said at a panel Friday during the Energy Bar Association’s Annual Meeting.

The commission for a long time had four main priorities when it comes to enforcement: market manipulation; serious violations of reliability standards; threats to transparency; and anticompetitive conduct, said Jones Day partner David Applebaum, a six-year FERC veteran and former director of the Division of Investigations. But in late 2021, it added a fifth: threats to the nation’s infrastructure and associated impacts on the environment and neighboring communities.

“I wouldn’t categorize the addition as any indication that we were investigating or penalizing conduct that had previously gone unaddressed, but rather as an indication that we had seen a compliance concern in this area,” FERC Office of Enforcement Director Janel Burdick said. “And specifically, I’m talking about violations of hydroelectric licenses, as well as certificate orders associated with [Natural Gas Act] Sections 3 and 7.”

While so far the new policy only applies to dams and natural gas infrastructure — with FERC getting some expanded authority over electric transmission in National Interest Electric Transmission Corridors — the commission could start to pursue similar cases in the power industry. Burdick, however, said those issues are still being hammered out by the commission, so it is unclear how this would play out.

One example of its new focus was a $700,000 settlement FERC approved with the natural gas storage facility outside Houston called Tres Palacios because it failed to conduct sonar surveys of its salt caverns as required in its certificate, said Bracewell partner Charles Mills. The firm admitted that it had not done the survey and even asked for an extension, which was denied (IN21-3).

“The things that can somewhat be taken away from it are: There was no finding of negligence, no finding harm, in order to find a violation,” Mills said. “It appears to be somewhat strict liability; if that certificate says you must do something, then you’ve got to do it.”

The Tres Palacios case was straightforward, but other cases involving the new priority could involve more litigation, such as when FERC pursues enforcement against a pipeline for its post-construction cleanup activities, in which whether that work was done properly can be a matter for debate, Mills said.

FERC has long pursued market manipulation cases, and some of those have worked their way through the courts after years of litigation and have set some precedent.

The commission alleged that BP manipulated natural gas prices in the Houston Ship Channel following Hurricane Ike in 2008 to benefit its positions elsewhere. In a decision last October, the 5th U.S. Circuit Court of Appeals agreed with BP on jurisdiction, said William Barksdale, energy regulatory counsel with Skadden, Arps, Slate, Meagher & Flom.

Most of the transactions in question were intrastate, and while FERC claimed authority because they impacted markets it regulates, the court disagreed and threw those out. The court told the commission to recalculate the fine based on the much smaller group of transactions it did have jurisdiction over, Barksdale said.

Another case where FERC managed to dodge having precedent set against some of its powers of disgorgement came in litigation with Coaltrain Energy, which is one of the firms that allegedly manipulated PJM’s market in the summer of 2010, said Mills. It and other firms used otherwise unprofitable up-to-congestion transactions to maximize marginal loss surplus allocation (MLSA) payments.

Coaltrain argued that FERC did not have the authority to order disgorgements, and the court agreed with the firm. The case was getting ready to go to trial, but FERC settled with Coaltrain for the $4 million in disgorgement alone, dropping significantly higher civil penalties it had initially sought, and got the court to vacate its opinion.

“So that’s over $50 million in fines [removed] from the case, but disgorgement is preserved,” said Mills. “To me, this indicates the importance that FERC places on disgorgement as a remedy but also [the] concern that its jurisdiction is being challenged, and they’re losing that jurisdictional point, and they don’t want that.”

Another one of the firms that allegedly engaged in the UTC-for-MLSA scheme back in 2010, Powhatan Energy Fund, recently wrapped up the litigation in a default judgment after it declared bankruptcy. That decision issued in March was important because it shows the commission has been winning on jurisdictional arguments, said Seema Jain, branch chief of Enforcement’s Division of Investigations.

“This is an important decision, because it’s the only final judgment on an enforcement case under the Federal Power Act,” said Jain. “So, you know, I want to highlight that. And the court granted FERC’s motion for default judgment against Powhatan and ordered disgorgement of $3.4 million, as well as $16.8 million in civil penalties. As part of that order, the court found that the commission’s well pleaded complaint and penalty order established that Powhatan committed market manipulation.”

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Entergy Reaches Settlement on $2.3B Texas Rate Case

Entergy (NYSE: ETR) said Wednesday its Texas subsidiary has struck a rate case settlement with state regulators to recover $2.3 billion for grid-modernization improvements it has completed.

Entergy Texas last year filed for base rate and rider revenues designed to collect $1.3 billion per year in non-fuel retail, an 11.2% ($131.4 million) increase on average across all customers classes. The settlement provides for a $54 million increase in base rate revenues, exclusive of incremental to costs being realigned from various riders and recovery factors, resulting in a non-fuel revenue requirement of $1.23 billion (53719).

The Texas Office of Public Utility Counsel, Texas Industrial Energy Consumers, Sierra Club, Kroger, Federal Executive Agencies and Walmart all signed on to the agreement, which is pending final approval from the PUC.

Entergy Texas spokesperson Kendra James said the settlement boils down to regulators agreeing to find that the company’s investments were prudent, reasonable and made for the customers’ benefit.

“It’s important to note that this amount is not an amount by which Entergy Texas rates will change. A portion of the cost of these investments will be recovered annually over the period in which they serve customers, which is decades for most large assets,” James said in an emailed statement to RTO Insider.

Entergy included the 993-MW Montgomery County Power Station, which went into commercial operations in January 2021 north of Houston, as part of the recent infrastructure upgrades. The plant was attributed as part of the reason MISO ultimately withdrew support for the only competitive transmission project it has ever recommended for MISO South. (See FERC Rejects Last-ditch Effort to Save Tx Project.)

The utility also pointed to its recent $41.3 million acquisition of the gas-fired, 146-MW Hardin County Peaking Facility from East Texas Electric Cooperative.

“Entergy Texas is continuously investing in customer-driven solutions to build a more reliable and resilient energy future for Southeast Texas communities,” Entergy Texas CEO Eliecer Viamontes said in a press release. “We are committed to balancing customer affordability with critical investments to help reduce outages and continue to strengthen the power grid.”

The company said it will also spend more than $2.5 billion by 2025 to continue replacing aging generation and harden infrastructure. It received the PUC’s approval last year to build the 1.2-GW natural gas and hydrogen-powered Orange County Advanced Power Station. Entergy recently broke ground on the project and expects it to be in service by 2026. (See Entergy, NextEra Tout Clean Energy Efforts.)

Entergy said the settlement’s terms will help ensure it stays “financially healthy and able to make the significant capital investments required to provide affordable, reliable and sustainable power.”

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Clements Discusses FERC’s Role in Grid Transition

WASHINGTON — Utility regulators should see planning for the grid’s transition as a practical — rather than political — act, FERC Commissioner Allison Clements told the Energy Bar Association’s annual meeting Thursday.

The nation’s grid is old and in need of upgrades, which will have to be resilient against increasing instances of extreme weather and cyber and physical attacks, while accommodating the changing resource mix. All those issues generate plenty of political debate, but Clements said it’s not her job to wade into that.

“It is the regulator’s job, and the utilities we regulate, and the stakeholders who are interested in the outcomes of that regulation, to protect customers and maintain reliability in the face of these challenging realities,” Clements said.

FERC and others with responsibility over the power system must tackle all the small and very large problems those changes produce at the same time. One of the biggest keys to it all is changing how transmission gets built.

“Right now, today, there is money on the table,” Clements said. “There is efficiency in the existing transmission system that we are not taking advantage of. And as I’ve been joking lately, I never thought in my life that I would become a cheerleader for something called grid enhancing technologies [GETs]. But I am a cheerleader for these things.”

GETs do involve changing the way the grid is run, but they are simple technologies and offer massive savings compared with building more transmission. Brattle Group has estimated that GETs could help integrate twice the volume of renewables as exist today without expanding transmission at all, so even if the real number is just 50% more renewables, that means massive savings, Clements said.

Tapping into the demand side can also make that transition easier, as evidenced by the 1.2 GW cut in demand resulting from a text message sent out by California’s government during last September’s heatwave. The text has come under criticism for scaring some consumers into thinking the grid was collapsing, but Clements said it at least showed there is plenty of untapped potential on the demand side.

“It’s not to suggest that we should go around scaring people by asking them to reduce demand,” Clements said. “The reality is that’s an opportunity that can be systematized.”

‘Never-ending Lunch Line’

FERC does have a role as it continues to work through issues around Order 2222 compliance, which required RTOs and ISOs to open their markets to aggregations of distributed energy resources.

The demand side and GETs are some of the “small things” that can help address the grid’s transition, but FERC is also focused on the larger issue of trying to clear out the 2,000 GW backlog in the country’s interconnection queues. (See LBNL: Interconnection Queues Grew 40% in 2022.)

“It’s like a never-ending lunch line, right?” Clements said. “You just wait and wait and wait. And it’s hard, and it’s expensive, and you lose efficiency and resources drop out of line.”

FERC has issued a Notice of Proposed Rulemaking (NOPR) that includes reforms that emerged as best practices around the country such as dealing with projects on a first-ready, first-served basis and processing them in clusters instead of one at a time. But the interconnection queues also need broader transmission planning reforms, which are the subject of another pending NOPR at the commission.

“I don’t think interconnection gets you all the way there, if you don’t fix the transmission system planning, and this maybe is perhaps the hardest, and the longest term,” said Clements. “But again, it’s a thing that FERC has taken action on. We issued a bipartisan proposal to improve regional transmission system planning and cost allocation.”

A major feature of that NOPR is longer-term scenario-based transmission planning that tries to figure out where generation and load will come from in the future and plan accordingly. It is impossible to predict the future, but by studying different scenarios, planners could come up with grid upgrades that produce significant benefits in multiple scenarios, Clements said.

Clements pointed to Edison Electric Institute figures showing that investor-owned utilities invested almost $28 billion in transmission in 2021, a figure that rose to about $30 billion last year.

“That’s the status quo,” she said. “So, whether or not FERC takes action on this rule, money is getting spent. Customers are ultimately holding the bag for that, right? We need to help direct that investment to a way where customers get the most bang for their buck — the most benefit at the lowest cost. And I think that this proposal has the opportunity to do that. Of course, we have to finalize it.”

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LS Power to Acquire Brazos Gas Generation

LS Power said Monday it has reached an agreement with Brazos Electric Power Cooperative to acquire 2.15 GW of its gas-fired generation in the ERCOT market.

The deal is a result of last year’s bankruptcy settlement between Brazos and the Texas grid operator, in which the cooperative agreed to sell its generation and become a transmission and distribution utility. Brazos owns about 4 GW of natural gas-fired capacity in ERCOT. (See Bankruptcy Judge Approves ERCOT-Brazos Settlement.)

The cooperative filed for bankruptcy in the wake of the February 2021 winter storm after being billed for $2.1 billion in wholesale prices. ERCOT later revised the amount due to the market to $1.89 billion. Brazos will use some of the transaction’s revenues to settle its debt.

LS Power is acquiring three plants as it continues to evaluate expansion opportunities in Texas:

  • Jack County, two baseload combined cycle units totaling 1,297 MW near Bridgeport;
  • Johnson County, a 280-MW combined cycle plant near Cleburne; and
  • RW Miller, four peaking units totaling 568 MW near Palo Pinto.

The company will fold the generation into a special-purpose affiliate that includes dual-fuel capability, firm gas and storage arrangements, and on-site fuel oil storage.

“These three generation projects we are acquiring provide critical, reliable energy supply to an ERCOT market that is experiencing continued load growth,” LS Power Generation President Nathan Hanson said in a statement. “These projects provide for considerable flexibility and operational redundancy, which are key to balancing the intermittency of renewables and supporting ERCOT’s reliability requirements.”

The acquisition will increase LS Power’s gas generation fleet to 16 GW. The gas fleet is a key element of its energy transition portfolio, the company said. It expects the transaction to close in early June after receiving regulatory approval.

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Regan: New EPA Standards Designed to not Jeopardize Grid Reliability

COLLEGE PARK, Md. — EPA Administrator Michael Regan on Thursday said his agency’s newly proposed carbon dioxide emission standards for power plants target “the most egregious sources” of pollution so “we can be sure that we don’t jeopardize the reliability” of the grid.

Regan was speaking to reporters after an event held at the University of Maryland College Park celebrating the official release of the standards earlier that morning. The complex rulemaking would set nationwide standards on CO2-emitting plants based on multiple variables, such as fuel type and frequency of usage. (See related story, EPA Proposes New Emissions Standards for Power Plants.)

They would require most new and existing large-capacity plants to use either carbon capture and sequestration or hydrogen co-firing no later than 2040, with some facilities subject to earlier deadlines based on characteristics. The most stringent standards are reserved for coal plants and new gas plants.

Left out are existing smaller, peaking gas units, defined as less than 300 MW with a capacity factor of less than 50%. For those, EPA is seeking comment on how it “should approach its legal obligation to establish emission guidelines.”

Regan was asked whether he was concerned about the number of gas-fired units left unregulated.

Michael Regan 2 2023-05-11 (RTO Insider LLC) Alt FI.jpgEPA Administrator Michael Regan answers questions from reporters. | © RTO Insider LLC

 

“I think the regulation covers a lot, quite frankly; the most and the largest,” he said. “Some of the smaller sources, some of those peaker plants that run less frequently, we will be thinking about how we tackle those as well. What we want to do with those [plants] is not use a blunt object. We want to be more surgical.”

Regan also emphasized that EPA had been consulting with utility CEOs, grid operators and states over the past two years to give the power sector “the certainty that they’re looking for without compromising reliability or affordability.” The proposal “takes into account all the energy requirements and needs of this country in a way that doesn’t compromise reliability, but the impacts to costs are also extremely negligible. So we believe we’ve threaded a really good needle here.”

Republicans do not agree.

The Biden administration’s “rush-to-green agenda is shutting down American energy and threatening the security and reliability of our electric grid,” Reps. Cathy McMorris Rodgers (R-Wash.) and Bill Johnson (R-Ohio) said in a statement. “We’re currently witnessing an electricity reliability crisis unfolding across the country. … The latest power plant rules being proposed by the EPA will make these problems worse by shutting down reliable energy sources prematurely and adding costly new burdens on sources like natural gas, which is responsible for a significant portion of our emissions reductions.”

Nor does Electric Power Supply Association CEO Todd Snitchler, who said that “once again, aspirational policy is getting ahead of operational reality. If finalized, these aggressive rules will undoubtedly drive up energy costs and lead to a substantial number of power plant retirements when experts have warned that we are already facing a reliability crisis due to accelerated retirements of dispatchable resources.”

But the Edison Electric Institute in a statement echoed some of Regan’s points, saying it valued “that EPA has constructively engaged with EEI and our member companies over the past 18 months, and we look forward to continuing to work with Administrator Regan and his team throughout the rulemaking process.”

The organization said it had lobbied for aligning the standards’ compliance deadlines with utilities’ existing transition plans and recognizing “the critical role existing and new natural gas generation plays — and will continue to play — in integrating more renewable energy and maintaining reliability.” It had also urged “a range of compliance flexibilities,” including hydrogen co-firing.

Legal Scrutiny

Environmental groups were nearly uniformly positive about the proposal, saying it would help the U.S. meet its emission-reduction goals.

“I think all of our stakeholders understand just how strong and how strategic this rule is. We’re also all living in a post-West Virginia [v. EPA] time,” Regan said, referring to the Supreme Court decision last year that struck down the Obama-era Clean Power Plan.

EEI noted in its statement that, “for the third time in nine years, EPA is proposing to limit carbon emissions from power plants using Clean Air Act Section 111.”

The group was referring to the CPP and the Trump administration’s Affordable Clean Energy rule, the latter of which would be repealed by the new rules.

“Last year, the Supreme Court threw out the Environmental Protection Agency’s overreaching mandates on power plant emissions,” said Sen. John Barrasso (R-Wyo.), ranking member of the Senate Energy and Natural Resources Committee. “The court rightfully confirmed Congress, not the EPA, has the authority to create environmental policy. Nothing has changed since then to give the unelected and unaccountable bureaucrats at the EPA this authority.”

Wes Moore 2023-05-11 (RTO Insider LLC) Alt FI.jpgMaryland Gov. Wes Moore celebrated the new standards and applauded the Biden administration’s work to address climate change. | © RTO Insider LLC

 

The court threw out the CPP, however, because it found that EPA lacks authority to compel generation shifting, ruling that it was a “set of state cap-and-trade schemes.” The agency is limited to requiring steps that individual plants can make “inside the fence line,” the court said. (See Supreme Court Rejects EPA Generation Shifting.)

But Sen. Joe Manchin (D-W.Va.), chair of the Senate Energy and Natural Resources Committee, announced on Wednesday that he would oppose every nominee to EPA before the committee because he said the agency did not even have the authority to regulate power plants’ emissions.

“Neither the [Infrastructure Investment and Jobs Act] nor the IRA gave new authority to regulate power plant emission standards,” Manchin said. “However, I fear that this administration’s commitment to their extreme ideology overshadows their responsibility to ensure long-lasting energy and economic security.”

Regan on Thursday reiterated that he was confident that the Biden administration’s version would be upheld. Asked how the failure of the CPP influenced the new rules, he said the proposal “is a completely separate rule from the Clean Power Plan.”

“This rule is well within the bounds of our statutory authority and the West Virginia Supreme Court decision,” he said. “We feel really good that we’re using the Clean Air Act’s traditional authority. We’re looking at the backdrop of the Inflation Reduction Act and those incentives for advanced technologies to put out a very strong rule that is really aggressive as it relates to combating the climate crisis. [I’m] very proud and very comfortable and confident that this is a very strong, legally sound, durable rule.”

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NERC Board of Trustees/MRC Briefs: May 10-11, 2023

Trustees Hold First Hybrid Meeting in DC Office

NERC’s Board of Trustees on Thursday approved the organization’s first-ever Level 3 alert — its highest-level action, indicating specific steps deemed essential for certain stakeholders to ensure reliable operation of the grid — at its quarterly meeting.

The alert, which concerns preparations for extreme cold weather, will be issued May 15.

The trustees — along with the Member Representatives Committee — gathered in person at NERC’s recently renovated offices in D.C. on Wednesday and Thursday, with other attendees observing via teleconference. The arrangement was announced at NERC’s November MRC meeting in New Orleans. (See “Board Makes Meeting Changes Official,” NERC Board of Trustees/MRC Briefs: Nov. 15-16, 2022.)

NERC’s next board and MRC meetings will be held in Ottawa, Ontario, Aug. 16-17 and will be fully in person, while the November meetings will be entirely virtual.

Board Chair Kenneth DeFontes thanked attendees for their willingness to adapt to the new format, saying the hybrid meeting schedule “opened the door to a new way … to engage [that is] going to be very beneficial.”

NERC CEO Jim Robb called the hybrid format the ERO’s “last major experiment in how to structure a board and MRC meeting” that seemed to be “a success so far.” He also praised the new office as a space for “more direct and … more intimate conversations” by the board and other stakeholders.

ERO to Issue First Level 3 Alert May 15

At the meeting, Darrell Moore, NERC’s director of bulk power system awareness, said the ERO needs the Level 3 alert in order “to understand how entities are taking steps to prepare for extreme cold weather conditions.”

Moore pointed out that the grid’s ability to withstand cold weather has been a major concern for the ERO and FERC over the past few years because of events such as the winter storms of 2021 and 2022. The commission recently approved new winter weather-focused reliability standards. (See FERC Orders New Reliability Standards in Response to Uri.)

Under the alert, responsible entities will be required to provide the following information by midnight ET Oct. 6:

  • for generator owners (GOs), their total net winter capacity megawatts, defined as the maximum output that generating equipment can supply to system load at the time of peak winter demand;
  • whether the entity has calculated an extreme cold weather temperature (ECWT) for some or all generating units;
  • the percent of net winter capacity megawatts capable of operating at the ECWT, along with the percent that have an ECWT above 32 degrees Fahrenheit and at various temperature ranges;
  • the percent of net winter capacity megawatts for which the GO has identified the generator cold weather critical component that could lead to forced derate or failure to start under freezing conditions;
  • whether any units experienced generator cold weather reliability events in the winter of 2022/23, and whether any units are believed to be at risk of the same event in the coming winter; and
  • for transmission operators and balancing authorities, whether they have updated their operating plans for cold weather emergencies, as described in the alert, or plan to before the next winter.

The alert also identifies eight “essential actions” for registered entities to take to prepare for cold weather. Unlike providing solicited information, implementing the essential actions is not mandatory. However, entities are required to acknowledge receipt of the alert and urged to follow the actions. After NERC receives entities’ responses, the ERO will analyze the results and report them to FERC by Nov. 3.

Board Approves INSM Data Request

The trustees also approved the issuance of a data request to responsible entities to help NERC meet FERC’s directive to develop a new standard requiring internal network security monitoring (INSM) on certain cyber systems.

At its January open meeting, the commission ordered NERC to submit new standards requiring INSM in all high-impact cyber systems, as well as in all medium-impact cyber systems with external routable connectivity (ERC). (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.)

FERC also ordered the ERO to study the risks of not implementing INSM and the feasibility of requiring it for other cyber systems not subject to the proposed standards, like low- and medium-impact systems without ERC. The study must be submitted to the commission by Jan. 18.

NERC’s data request will seek information from entities regarding the number of substations and generation locations containing medium-impact cyber systems, with or without ERC; the number of locations with low-impact systems; potential logistical, technological or other challenges involved in extending INSM to additional cyber systems; and possible alternative actions to lessen these systems’ risks without INSM. Responses must be submitted within 60 days of the request’s issuance.

In addition, the board accepted the Texas Reliability Entity’s revised regional standards development process, which the RE’s Board of Directors approved in February. The revisions are intended to clarify the document and improve the efficiency of the standards development process; promote consistency with other RE materials and with NERC’s Standard Processes Manual; and promote stakeholder participation.

Leadership Changes; Thomas Honored

Robb announced the elevation of Howard Gugel, previously NERC’s vice president of engineering and standards, as the new vice president of compliance assurance and registration. While Gugel has been informally filling the role since February because of Mechelle Thomas’ long illness, he officially assumed it Thursday.

Thomas died May 1. She worked at NERC for nearly 11 years, initially as senior director of internal audit and corporate risk management and for the last four years in the compliance assurance position.

Robb led a moment of silence for her and was one of several during the meetings to pay tribute to her. While Robb discussed Thomas’ multiple accomplishments at NERC, such as launching the organization’s employee resource groups and promoting diversity, equity and inclusion within the organization, SERC Reliability CEO Jason Blake remembered her as “a true partner” to the REs who was “always involved with and collaborating” with RE staff.

MRC Chair Jennifer Flandermeyer on Wednesday called Thomas “a very special lady with a wide impact on the industry” and called her passing “a hard loss” for her colleagues.

“She was just a wonderful teammate; she was an adviser and a friend to me personally, and to … many of you,” Robb said. “She made an impact on people in both big and small ways, and we’re only starting to realize the magnitude of the shadow that she cast over the last couple of weeks. So to say that we’ve been devastated by this is an understatement.”

Soo Jin Kim, a 10-year veteran at NERC who most recently headed the organization’s Power Risk Issues and Strategic Management group, was approved to succeed Gugel as vice president of engineering and standards. Kim will begin her new role next week.

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MISO Picks Republic Transmission for 1st LRTP Competitive Project

MISO has chosen LS Power’s Republic Transmission to build the first competitive project emerging from the RTO’s long-range transmission plan (LRTP).

In a selection report published Thursday, MISO said Republic’s $77 million proposal to construct the Hiple 345-kV line crossing the Indiana-Michigan border boasted a “well-supported project implementation cost estimate, a superior revenue requirement commitment and a well-reasoned routing strategy.”

The project is the first competitively bid project to come from MISO’s inaugural, $10 billion long-range transmission plan portfolio. The RTO originally estimated the project would cost about $254 million based on a 55-mile route, which Republic said it will reduce to 23 miles.

The project entails a new double-circuit 345-kV line that will connect Northern Indiana Public Service Co.’s Hiple substation in LaGrange County, Ind., to Michigan Electric Transmission Co.’s (METC) future Duck Lake substation in Michigan.

MISO said it’s still uncertain where the Hiple line will connect with METC’s line on the state line and that its request for proposal required all proposed routes to cross the border “within 10 miles east or west of a point identified by METC as a possible point of interconnection.”

Only the Indiana portion of the transmission line was eligible for MISO’s competitive transmission process. However, Indiana this month expanded its state right of first refusal law to include multistate projects identified by RTOs in addition to projects necessary for reliability. (See New Law Expands Indiana ROFR Law for Transmission Buildout.)

MISO said Republic was careful to avoid environmentally protected areas in its proposed routing to the Michigan point of interconnection.

“Republic Transmission’s proposal reflects an efficient project cost and design,” Jeremiah Doner, MISO’s director of cost allocation and competitive transmission, said in a press release. “This includes a superior 40-year cost containment commitment and a well-reasoned project implementation strategy.”

In a press release, LS Power President Paul Thessen thanked MISO “for conducting a thorough competitive process to achieve cost efficient transmission solutions, which is estimated to provide consumers with more than 30% savings as compared to MISO’s initial estimate.”

The grid operator said it received six other proposals from two developers. Cost estimates for those proposals ranged from $97 million to $125 million and used either a 25- or 30-mile route. MISO does not reveal the identity of developers who do not win contracts.

The RTO gave Republic’s proposal an overall score of 93 out of 100; the other proposals ranked from 81 to 64. MISO opened the RFP last September and developers had until Jan. 11 to submit applications.

Republic said it will use a concrete or steel monopole design and pledged to complete the project two years ahead of MISO’s envisioned June 1, 2030, in-service date. MISO noted that, unlike the other two hopefuls, Republic is already cleared to operate as a public utility in Indiana and doesn’t have to seek approval from the state’s Utility Regulatory Commission to begin construction.

Other Project Decisions Loom

The Hiple RFP is the first of five RFPs stemming from MISO’s $10 billion, 18-project LRTP package of 345-kV lines approved in July.

MISO has two other RFP application windows open. Proposals are due May 19 for the $161 million Fairport-Denny project, crossing the Iowa-Missouri border. The RTO released another LRTP RFP in March, which seeks bids on the $556 million Denny to Zachary to Thomas Hill 345-kV project, part of which will link up with the Fairport-Denny project. (See MISO Begins LRTP’s 2nd RFP Process.)

MISO has said it will release two other RFPs in July. It plans to open bidding for the $12 million Deadend to Tremval 345-kV project in Wisconsin on July 11, followed by a July 24 opening of the bid window for a $23 million, 345-kV line segment from the Iowa-Illinois border to the Ipava substation in Illinois. The LRTP portfolio marks the first time MISO is simultaneously managing multiple competitive bid processes.

Only about 10% of the first LRTP portfolio is open to competitive bidding because of state ROFR laws and the upgrade nature of some of the projects. (See MISO Board Approves $10B in Long-range Tx Projects.) However, the Iowa Supreme Court in March temporarily invalidated the state’s ROFR law, throwing $2.64 billion worth of LRTP work across five Iowa projects assigned to incumbent developers into uncertainty. (See Iowa Regulators Ponder MISO Tx Projects After ROFR Ruling.)

Iowa staff are still working through the possible implications for transmission construction. The state’s Utilities Board replaced two of its three-member board on May 1. During a May 11 Organization of MISO States meeting, Iowa Board Member Joshua Byrnes told other MISO regulators that he was working feverishly to bring the new members up to speed on issues.

This isn’t the first time Republic has been awarded a MISO transmission project. The company and partner Big Rivers Electric completed the $65 million, 31-mile Duff-Coleman 345-kV transmission project in Southern Indiana and Western Kentucky ahead of schedule in 2020 after their bid was selected by MISO planners in 2016. Republic’s original $49.8 million proposal beat out 10 other developers’ bids. (See LS Power Unit Wins MISO’s First Competitive Project.) MISO originally placed a $59 million planning-level estimate on the work and estimates the project will provide $1 billion in benefits to its central region over the next two decades.